Black Hills (BKH) 10-Q 7 Aug 18 2018 Q2 Quarterly report Financial data

Document and Entity Information

Document and Entity Information Document - shares	6 Months Ended
	Jun. 30, 2018	Jul. 31, 2018
Document and Entity Information [Abstract]
Entity Registrant Name	BLACK HILLS CORP /SD/
Entity Central Index Key	1,130,464
Document Type	10-Q
Document Period End Date	Jun. 30, 2018
Amendment Flag	false
Document Fiscal Year Focus	2,018
Document Fiscal Period Focus	Q2
Current Fiscal Year End Date	--12-31
Entity Current Reporting Status	Yes
Entity Filer Category	Large Accelerated Filer
Entity Common Stock, Shares Outstanding		53,594,876
Entity Well-known Seasoned Issuer	Yes
Entity Voluntary Filers	No

Condensed Consolidated Statemen

Condensed Consolidated Statements of Income (unaudited) - USD ($) shares in Thousands, $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2018	Jun. 30, 2017	Jun. 30, 2018	Jun. 30, 2017
Income Statement [Abstract]
Revenue	$ 355,704	$ 341,829	$ 931,093	$ 889,357
Operating expenses:
Fuel, purchased power and cost of natural gas sold	104,661	98,164	352,300	317,941
Operations and maintenance	118,282	111,897	234,378	226,449
Depreciation, depletion and amortization	48,709	46,825	97,299	93,527
Taxes - property, production and severance	13,976	13,072	27,276	26,458
Other operating expenses	525	2,075	2,015	5,000
Total operating expenses	286,153	272,033	713,268	669,375
Operating income	69,551	69,796	217,825	219,982
Interest charges -
Interest expense incurred (including amortization of debt issuance costs, premiums and discounts)	(35,425)	(35,072)	(70,880)	(70,130)
Allowance for funds used during construction - borrowed	511	822	644	1,308
Capitalized interest	60	58	77	133
Interest income	320	257	630	298
Allowance for funds used during construction - equity	242	794	310	1,286
Other income (expense), net	(1,551)	(76)	(1,723)	(195)
Total other income (expense), net	(35,843)	(33,217)	(70,942)	(67,300)
Income before income taxes	33,708	36,579	146,883	152,682
Income tax benefit (expense)	(6,541)	(10,652)	19,261	(45,040)
Income from continuing operations	27,167	25,927	166,144	107,642
Net (loss) from discontinued operations	(2,427)	(616)	(4,770)	(2,185)
Net income	24,740	25,311	161,374	105,457
Net income attributable to noncontrolling interest	(2,823)	(3,116)	(6,453)	(6,739)
Net income from continuing operations	24,344	22,811	159,691	100,903
Net income available for common stock	$ 21,917	$ 22,195	$ 154,921	$ 98,718
Earnings Per Share, Basic [Abstract]
Income from continuing operations, Basic (usd per share)	$ 0.46	$ 0.43	$ 2.99	$ 1.90
(Loss) from discontinued operations, Basic (usd per share)	(0.05)	(0.01)	(0.09)	(0.04)
Earnings (loss) per share, Basic (usd per share)	0.41	0.42	2.90	1.86
Earnings Per Share, Diluted [Abstract]
Income from continuing operations, Diluted (usd per share)	0.45	0.41	2.94	1.83
(Loss) from discontinued operations, Diluted (usd per share)	(0.05)	(0.01)	(0.09)	(0.04)
Earnings (loss) per share, Diluted (usd per share)	$ 0.40	$ 0.40	$ 2.85	$ 1.79
Weighted Average Number of Shares Outstanding, Basic and Diluted [Abstract]
Basic (in shares)	53,355	53,229	53,337	53,191
Diluted (in shares)	54,520	55,384	54,361	55,179
Dividends declared per share of common stock (usd per share)	$ 0.475	$ 0.445	$ 0.950	$ 0.890

Condensed Consolidated Stateme3

Condensed Consolidated Statements of Comprehensive Income (unaudited) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2018	Jun. 30, 2017	Jun. 30, 2018	Jun. 30, 2017
Net income	$ 24,740	$ 25,311	$ 161,374	$ 105,457
Other comprehensive income (loss), net of tax:
Reclassification adjustments of benefit plan liability - prior service cost	(35)	(31)	(70)	(62)
Reclassification adjustments of benefit plan liability - net gain (loss)	487	268	973	528
Other comprehensive income (loss), net of tax	1,161	789	2,421	1,942
Comprehensive income	25,901	26,100	163,795	107,399
Less: comprehensive income attributable to noncontrolling interest	(2,823)	(3,116)	(6,453)	(6,739)
Comprehensive income available for common stock	23,078	22,984	157,342	100,660
Interest rate swaps
Other comprehensive income (loss), net of tax:
Reclassification of net realized (gains) losses	561	464	1,122	985
Commodity Contract
Other comprehensive income (loss), net of tax:
Reclassification of net realized (gains) losses	118	(243)	594	(424)
Net unrealized gains (losses)	$ 30	$ 331	$ (198)	$ 915

Condensed Consolidated Stateme4

Condensed Consolidated Statements of Comprehensive Income (Loss) (unaudited) (Parenthetical) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2018	Jun. 30, 2017	Jun. 30, 2018	Jun. 30, 2017
Reclassification adjustment of benefit plan - prior service cost, (tax) benefit	$ 9	$ 18	$ 19	$ 35
Reclassification adjustment of benefit plan liabilities, (tax) benefit	(135)	(146)	(271)	(300)
Interest rate swaps
Reclassification of net realized gains/losses, (tax) benefit	(152)	(249)	(304)	(530)
Commodity Contract
Net unrealized gains/losses, (tax) benefit	(18)	(194)	51	(536)
Reclassification of net realized gains/losses, (tax) benefit	$ (45)	$ 143	$ (190)	$ 249

Condensed Consolidated Balance

Condensed Consolidated Balance Sheets (unaudited) - USD ($) $ in Thousands	Jun. 30, 2018	Dec. 31, 2017	Jun. 30, 2017
Current assets:
Cash and cash equivalents	$ 8,630	$ 15,420	$ 11,528
Restricted cash	3,084	2,820	2,534
Accounts receivable, net	175,612	248,330	166,760
Materials, supplies and fuel	95,454	113,283	95,488
Derivative assets, current	666	304	639
Income tax receivable, net	11,653	0	0
Regulatory assets, current	50,565	81,016	53,061
Other current assets	31,431	25,367	20,768
Current assets held for sale	3,557	84,242	8,478
Total current assets	380,652	570,782	359,256
Investments	41,148	13,090	12,761
Property, plant and equipment	5,702,065	5,567,518	5,423,160
Less: accumulated depreciation and depletion	(1,087,689)	(1,026,088)	(964,549)
Total property, plant and equipment, net	4,614,376	4,541,430	4,458,611
Other assets:
Goodwill	1,299,454	1,299,454	1,299,454
Intangible assets, net	7,155	7,559	7,972
Regulatory assets, non-current	210,137	216,438	244,099
Other assets, non-current	17,207	10,149	13,594
Noncurrent assets held for sale	0	0	113,999
Total other assets, non-current	1,533,953	1,533,600	1,679,118
TOTAL ASSETS	6,570,129	6,658,902	6,509,746
Current liabilities:
Accounts payable	104,718	160,887	99,296
Accrued liabilities	190,339	219,462	191,806
Derivative liabilities, current	485	2,081	676
Accrued income taxes, net	0	1,022	5,160
Regulatory liabilities, current	52,102	6,832	17,305
Notes payable	121,800	211,300	107,975
Current maturities of long-term debt	255,743	5,743	5,743
Current liabilities held for sale	5,448	41,774	10,904
Total current liabilities	730,635	649,101	438,865
Long-term debt	2,858,068	3,109,400	3,160,302
Deferred credits and other liabilities:
Deferred income tax liabilities, net	289,814	336,520	609,843
Regulatory liabilities, non-current	497,929	478,294	199,005
Benefit plan liabilities	162,199	159,646	176,102
Other deferred credits and other liabilities	104,951	105,735	112,550
Non-current liabilities held for sale	0	0	23,048
Total deferred credits and other liabilities	1,054,893	1,080,195	1,120,548
Commitments and contingencies (See Notes 9, 11, 16, 17)
Equity:
Common stock $1 par value; 100,000,000 shares authorized; issued 53,661,850; 53,579,986; and 53,513,521 shares, respectively	53,662	53,580	53,514
Additional paid-in capital	1,154,947	1,150,285	1,145,493
Retained earnings	652,642	548,617	512,498
Treasury stock, at cost – 64,981; 39,064; and 39,329 shares, respectively	(3,642)	(2,306)	(2,325)
Accumulated other comprehensive income (loss)	(38,763)	(41,202)	(32,941)
Total stockholders’ equity	1,818,846	1,708,974	1,676,239
Noncontrolling interest	107,687	111,232	113,792
Total equity	1,926,533	1,820,206	1,790,031
TOTAL LIABILITIES AND TOTAL EQUITY	$ 6,570,129	$ 6,658,902	$ 6,509,746

Condensed Consolidated Balance6

Condensed Consolidated Balance Sheets (unaudited) (Parenthetical) - $ / shares	Jun. 30, 2018	Dec. 31, 2017	Jun. 30, 2017
Statement of Financial Position [Abstract]
Common Stock, Par Value (usd per share)	$ 1	$ 1	$ 1
Common Stock, Shares Issued	53,661,850	53,579,986	53,513,521
Treasury Stock, Shares	64,981	39,064	39,329
Common Stock, Shares Authorized	100,000,000	100,000,000	100,000,000

Condensed Consolidated Stateme7

Condensed Consolidated Statements of Cash Flows (unaudited) - USD ($) $ in Thousands	6 Months Ended
	Jun. 30, 2018	Jun. 30, 2017
Operating activities:
Net income	$ 161,374	$ 105,457
Loss from discontinued operations, net of tax	4,770	2,185
Income from continuing operations	166,144	107,642
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization	97,299	93,527
Deferred financing cost amortization	3,694	4,138
Stock compensation	5,221	6,589
Deferred income taxes	(21,419)	52,385
Employee benefit plans	6,911	5,717
Other adjustments, net	4,884	(6,445)
Changes in certain operating assets and liabilities:
Materials, supplies and fuel	18,492	7,753
Accounts receivable, unbilled revenues and other operating assets	50,711	94,591
Accounts payable and other operating liabilities	(96,394)	(117,134)
Regulatory assets - current	55,637	3,086
Regulatory liabilities - current	19,990	5,908
Other operating activities, net	(1,372)	(125)
Net cash provided by operating activities of continuing operations	309,798	257,632
Net cash provided by operating activities of discontinued operations	903	5,237
Net cash provided by operating activities	310,701	262,869
Investing activities:
Property, plant and equipment additions	(156,748)	(154,294)
Purchase of investment	(24,429)	0
Other investing activities	(373)	238
Net cash provided by (used in) investing activities of continuing operations	(181,550)	(154,056)
Net cash provided by (used in) investing activities of discontinued operations	18,024	(9,474)
Net cash provided by (used in) investing activities	(163,526)	(163,530)
Financing activities:
Dividends paid on common stock	(50,879)	(47,544)
Common stock issued	1,074	2,965
Net (payments) borrowings of short-term debt	(89,500)	11,375
Long-term debt - repayments	(2,871)	(52,871)
Distributions to noncontrolling interest	(9,998)	(8,335)
Other financing activities	(1,527)	(6,659)
Net cash provided by (used in) financing activities	(153,701)	(101,069)
Net change in cash, cash equivalents and restricted cash	(6,526)	(1,730)
Cash, cash equivalents and restricted cash at beginning of period	18,240	15,792
Cash, cash equivalents and restricted cash at end of period	$ 11,714	$ 14,062

Management's Statement_

Management's Statement:	6 Months Ended
	Jun. 30, 2018
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Management's Statement	MANAGEMENT’S STATEMENT The unaudited Condensed Consolidated Financial Statements included herein have been prepared by Black Hills Corporation (together with our subsidiaries the “Company,” “us,” “we,” or “our”), pursuant to the rules and regulations of the SEC. Certain information and footnote disclosures normally included in financial statements prepared in accordance with accounting principles generally accepted in the United States of America have been condensed or omitted pursuant to such rules and regulations; however, we believe that the footnotes adequately disclose the information presented. These Condensed Consolidated Financial Statements should be read in conjunction with the consolidated financial statements and the notes thereto included in our 2017 Annual Report on Form 10-K filed with the SEC. Segment Reporting We conduct our operations through the following reportable segments: Electric Utilities, Gas Utilities, Power Generation and Mining. Our reportable segments are based on our method of internal reporting, which is generally segregated by differences in products, services and regulation. All of our operations and assets are located within the United States. On November 1, 2017, the BHC board of directors approved a complete divestiture of our Oil and Gas segment. The Oil and Gas segment assets and liabilities are classified as held for sale and the results of operations are shown in income (loss) from discontinued operations, excluding certain general and administrative costs and interest expense which do not meet the criteria for income (loss) from discontinued operations. As of June 30, 2018, we have sold nearly all oil and gas assets. Transaction closing for the last few assets and final accounting are expected within the third quarter. The closing of the oil and gas office will occur in August. See Note 18 for more information on discontinued operations. Use of Estimates and Basis of Presentation The information furnished in the accompanying Condensed Consolidated Financial Statements reflects certain estimates required and all adjustments, including accruals, which are, in the opinion of management, necessary for a fair presentation of the June 30, 2018 , December 31, 2017 , and June 30, 2017 financial information and are of a normal recurring nature. Certain industries in which we operate are highly seasonal, and revenue from, and certain expenses for, such operations may fluctuate significantly among quarterly periods. Demand for electricity and natural gas is sensitive to seasonal cooling, heating and industrial load requirements, as well as changes in market prices. In particular, the normal peak usage season for electric utilities is June through August while the normal peak usage season for gas utilities is November through March. Significant earnings variances can be expected between the Gas Utilities segment’s peak and off-peak seasons. Due to this seasonal nature, our results of operations for the three and six months ended June 30, 2018 and June 30, 2017 , and our financial condition as of June 30, 2018 , December 31, 2017 , and June 30, 2017 , are not necessarily indicative of the results of operations and financial condition to be expected as of or for any other period. All earnings per share amounts discussed refer to diluted earnings per share unless otherwise noted. Cash and Cash Equivalents and Restricted Cash For purposes of the cash flow statements, we consider all highly liquid investments with original maturities of three months or less at the time of purchase to be cash equivalents. Investments We account for investments that we do not control under the cost method of accounting as we do not have the ability to exercise significant influence over the operating and financial policies of the investee. The cost method investments are recorded at cost and we record dividend income when applicable dividends are declared. Recently Issued Accounting Standards Leases, ASU 2016-02 In February 2016, the FASB issued ASU 2016-02, Leases (Topic 842) , which supersedes ASC 840, Leases. This ASU requires lessees to recognize a right-of-use asset and lease liability on the balance sheet for most leases, whereas today only financing-type lease liabilities (capital leases) are recognized on the balance sheet. In addition, the definition of a lease has been revised in regards to when an arrangement conveys the right to control the use of the identified asset under the arrangement which may result in changes to the classification of an arrangement as a lease. The ASU does not significantly change the lessees’ recognition, measurement and presentation of expenses and cash flows from the previous accounting standard. Lessors’ accounting under the ASU is largely unchanged from the previous accounting standard. The ASU expands the disclosure requirements of lease arrangements. Under the current guidance, lessees and lessors will use a modified retrospective transition approach, which requires application of the new guidance at the beginning of the earliest comparative period presented in the year of adoption. The guidance is effective for interim and annual reporting periods beginning after December 15, 2018, with early adoption permitted. In January 2018, the FASB issued amendments to the new lease standard, ASU No. 2018-01, allowing an entity to elect not to assess whether certain land easements are, or contain, leases when transitioning to the new lease standard. The FASB also issued additional amendments to the new lease standard in July 2018, ASU No. 2018-11, allowing companies to adopt the new standard with a cumulative effect adjustment as of the beginning of the year of adoption with prior year comparative financial information and disclosures remaining as previously reported. We expect to adopt this standard on January 1, 2019. For existing or expired land easements that were not previously accounted for as a lease, we anticipate electing the practical expedient which provides for no assessment of these easements. Further, we anticipate adopting the new standard with a cumulative effect adjustment with prior year comparative financial information remaining as previously reported when transitioning to the new standard. The standard also provides a transition practical expedient, commonly referred to as the “package of three”, that must be taken together and allows entities to (1) not reassess whether existing contracts contain leases, (2) carryforward the existing lease classification, and (3) not reassess initial direct costs associated with existing leases. We expect to elect the “package of three” practical expedient. We continue to evaluate the additional transition practical expedients available under the guidance and the impact of this new standard on our financial position, results of operations and cash flows. We are finalizing the process of identifying and categorizing our lease contracts and evaluating our current business processes relating to leases. We have selected and configured a new lease software solution that we are currently testing. We also continue to monitor utility industry lease implementation guidance that may change existing and future lease classification. Derivatives and Hedging: Targeted Improvements to Accounting for Hedging Activities, ASU 2017-12 In August 2017, the FASB issued ASU 2017-12, Derivatives and Hedging (Topic 815): Targeted Improvements to Accounting for Hedging Activities. This standard better aligns risk management activities and financial reporting for hedging relationships, simplifies hedge accounting requirements and improves disclosures of hedging arrangements. This ASU is effective for fiscal years beginning after December 15, 2018, with early adoption permitted. We do not anticipate the adoption of this guidance to have a material impact on our financial position, results of operations or cash flows. Simplifying the Test for Goodwill Impairment, ASU 2017-04 In January 2017, the FASB issued ASU 2017-04, Simplifying the Test for Goodwill Impairment (Topic 350) by eliminating step 2 from the goodwill impairment test. Under the new guidance, if the carrying amount of a reporting unit exceeds its fair value, an impairment loss will be recognized in an amount equal to that excess, limited to the amount of goodwill allocated to that reporting unit. The new standard is effective for interim and annual reporting periods beginning after December 15, 2019, applied on a prospective basis with early adoption permitted. We do not anticipate the adoption of this standard to have any impact on our financial position, results of operations or cash flows. Recently Adopted Accounting Standards Revenue from Contracts with Customers, ASU 2014-09 Effective January 1, 2018, we adopted ASU 2014-09, Revenue from Contracts with Customers (Topic 606) , and its related amendments (collectively known as ASC 606). Under this standard, revenue is recognized when a customer obtains control of promised goods or services in an amount that reflects the consideration the entity expects to receive in exchange for those goods or services. In addition, the standard requires disclosure of the nature, amount, timing and uncertainty of revenue and cash flows arising from contracts with customers. We applied the five-step method outlined in the ASU to all in-scope revenue streams and elected the modified retrospective implementation method. Implementation of the standard did not have a material impact on our financial position, results of operations or cash flows. Implementation of the standard did not have a significant impact on the measurement or recognition of revenue; therefore, no cumulative adoption adjustment to the opening balance of Retained earnings at the date of initial application was necessary. The additional disclosures required by the ASU are included in Note 2. Compensation - Retirement Benefits: Improving the Presentation of Net Periodic Pension Cost and Net Periodic Post-Retirement Benefit Cost, ASU 2017-07 Effective January 1, 2018, we adopted ASU 2017-07, Compensation – Retirement Benefits (Topic 715): Improving the Presentation of Net Periodic Pension Cost and Net Periodic Post-Retirement Benefit Cost . The standard requires employers to report the service cost component in the same line item(s) as other compensation costs, and require the other components of net periodic pension and post-retirement benefit costs to be separately presented in the income statement outside of income from operations. Additionally, only the service cost component may be eligible for capitalization, when applicable. However, all cost components remain eligible for capitalization under FERC regulations. The capitalization of only the service cost component of net periodic pension and post-retirement benefit costs in assets was applied on a prospective basis for the six months ended June 30, 2018. Retrospective impact was not material and therefore prior year presentation was not changed. For our rate-regulated entities, we capitalize the other components of net periodic benefit costs into regulatory assets or regulatory liabilities and maintain a FERC-to-GAAP reporting difference for these capitalized costs. The presentation changes required for net periodic pension and post-retirement costs resulted in offsetting changes to Operating income and Other income. Implementation of the standard did not have a material impact on our financial position, results of operations or cash flows. Statement of Cash Flows: Classification of Certain Cash Receipts and Cash Payments, ASU 2016-15 Effective January 1, 2018, we adopted ASU 2016-15, Statement of Cash Flows (Topic 230): Classification of Certain Cash Receipts and Cash Payments (a consensus of the Emerging Issues Task Force). This ASU requires changes in the presentation of certain items, including but not limited to, debt prepayment or debt extinguishment costs; contingent consideration payments made after a business combination; proceeds from the settlement of insurance claims; proceeds from the settlement of corporate-owned life insurance policies and distributions received from equity method investees. We implemented this standard effective January 1, 2018 using the retrospective transition method. This standard had no impact on our financial position, results of operations or cash flows. Statement of Cash Flows: Restricted Cash, ASU 2016-18 Effective January 1, 2018, we adopted ASU 2016-18, Statement of Cash Flows (Topic 230): Restricted Cash. This ASU provides guidance on the presentation of restricted cash or restricted cash equivalents and reduces the diversity in practice. This ASU requires amounts generally described as restricted cash and restricted cash equivalents to be included with cash and cash equivalents when reconciling beginning-of-period and end-of-period total amounts on the statement of cash flows. We elected, as permitted by the standard, to early adopt ASU 2016-18 retrospectively as of January 1, 2017 and have applied it to all periods presented herein. The adoption of ASU 2016-18 did not have a material impact to our condensed consolidated financial statements. The effect of the adoption of ASU 2016-18 on our Condensed Consolidated Statements of Cash Flows was to include restricted cash balances in the beginning and end of period balances of cash, cash equivalents, and restricted cash. The change in restricted cash was previously disclosed in investing activities in the Condensed Consolidated Statements of Cash Flows.

Revenue_

Revenue:	6 Months Ended
	Jun. 30, 2018
Revenue from Contract with Customer [Abstract]
Revenue	REVENUE Revenue Recognition Revenues are recognized in an amount that reflects the consideration we expect to receive in exchange for goods or services, when control of the promised goods or services is transferred to our customers. Our primary types of revenue contracts are: • Regulated natural gas and electric utility services tariffs - Our utilities have regulated operations, as defined by ASC 980, that provide services to regulated customers under rates, charges, terms and conditions of service, and prices determined by the jurisdictional regulators designated for our service territories. Collectively, these rates, charges, terms and conditions are included in a tariff, which governs all aspects of the provision of our regulated services. Our regulated services primarily encompass single performance obligations material to the context of the contract for delivery of either commodity natural gas, commodity electricity, natural gas transportation or electric transmission services. These service revenues are variable based on quantities delivered, influenced by seasonal business and weather patterns. Tariffs are only permitted to be changed through a rate-setting process involving the regulator-empowered statute to establish contractual rates between the utility and its customers. All of our utilities’ regulated sales are subject to regulatory-approved tariffs. • Power sales agreements - Our electric utilities and power generation segments have long-term wholesale power sales agreements with other load-serving entities, including affiliates, for the sale of excess power from owned generating units. These agreements include a combination of “take or pay” arrangements, where the customer is obligated to pay for the energy regardless of whether it actually takes delivery, as well as “requirements only” arrangements, where the customer is only obligated to pay for the energy the customer needs. In addition to these long-term contracts, Black Hills also sells excess energy to other load-serving entities on a short-term basis as a member of the Western States Power Pool. The pricing for all of these arrangements is included in the executed contracts or confirmations, reflecting the standalone selling price and is variable based on energy delivered. • Coal supply agreements - Our mining segment sells coal primarily under long-term contracts to utilities for use at their power generating plants, including affiliate electric utilities, and an affiliate non-regulated power generation entity. The contracts include a single promise to supply coal necessary to fuel the customers’ facilities during the contract term. The transaction price is established in the coal supply agreements, including cost-based agreements with the affiliated regulated utilities, and is variable based on tons of coal delivered. • Other non-regulated services - Our natural gas and electric utility segments also provide non-regulated services primarily comprised of appliance repair service and protection plans, electric and natural gas technical infrastructure construction and maintenance services, and in Nebraska and Wyoming, an unbundled natural gas commodity offering under the regulatory-approved Choice Gas Program. Revenue contracts for these services generally represent a single performance obligation with the price reflecting the standalone selling price stated in the agreement, and the revenue is variable based on the units delivered or services provided. The following tables depict the disaggregation of revenue, including intercompany revenue, from contracts with customers by customer type and timing of revenue recognition for each of the reporting segments, for the three and six months ended June 30, 2018 . Sales tax and other similar taxes are excluded from revenues. Three Months Ended June 30, 2018 Electric Utilities Gas Utilities Power Generation Mining Inter-company Revenues Total Customer types: (in thousands) Retail $ 145,377 $ 135,863 $ — $ 16,345 $ (7,979 ) $ 289,606 Transportation — 29,011 — — (301 ) 28,710 Wholesale 8,191 — 12,743 — (11,613 ) 9,321 Market - off-system sales 4,938 162 — — (1,660 ) 3,440 Transmission/Other 13,356 11,672 — — (3,644 ) 21,384 Revenue from contracts with customers 171,862 176,708 12,743 16,345 (25,197 ) 352,461 Other revenues 1,754 912 9,141 554 (9,118 ) 3,243 Total revenues $ 173,616 $ 177,620 $ 21,884 $ 16,899 $ (34,315 ) $ 355,704 Timing of revenue recognition: Services transferred at a point in time $ — $ — $ — $ 16,345 $ (7,978 ) $ 8,367 Services transferred over time 171,862 176,708 12,743 — (17,219 ) 344,094 Revenue from contracts with customers $ 171,862 $ 176,708 $ 12,743 $ 16,345 $ (25,197 ) $ 352,461 Six Months Ended June 30, 2018 Electric Utilities Gas Utilities Power Generation Mining Inter-company Revenues Total Customer types: (in thousands) Retail $ 292,434 $ 477,257 $ — $ 32,902 $ (15,821 ) $ 786,772 Transportation — 70,681 — — (710 ) 69,971 Wholesale 17,241 — 26,676 — (23,826 ) 20,091 Market - off-system sales 9,082 589 — — (4,182 ) 5,489 Transmission/Other 26,427 24,341 — — (7,275 ) 43,493 Revenue from contracts with customers 345,184 572,868 26,676 32,902 (51,814 ) 925,816 Other revenues 1,987 2,096 18,311 1,125 (18,242 ) 5,277 Total revenues $ 347,171 $ 574,964 $ 44,987 $ 34,027 $ (70,056 ) $ 931,093 Timing of revenue recognition: Services transferred at a point in time $ — $ — $ — $ 32,902 $ (15,820 ) $ 17,082 Services transferred over time 345,184 572,868 26,676 — (35,994 ) 908,734 Revenue from contracts with customers $ 345,184 $ 572,868 $ 26,676 $ 32,902 $ (51,814 ) $ 925,816 The majority of our revenue contracts are based on variable quantities delivered; any fixed consideration contracts with an expected duration of one year or more are immaterial to our consolidated revenues. Variable consideration constraints in the form of discounts, rebates, credits, price concessions, incentives, performance bonuses, penalties or other similar items are not material for our revenue contracts. We are the principal in our revenue contracts, as we have control over the services prior to those services being transferred to the customer. Revenue Not in Scope of ASC 606 Other revenues included in the tables above include our revenue accounted for under separate accounting guidance, including lease revenue under ASC 840 and alternative revenue programs revenue under ASC 980. The majority of our lease revenue is related to a 20-year power sale agreement between Colorado IPP and affiliate Colorado Electric. This agreement is accounted for as a direct financing lease whereby Colorado IPP receives revenue for energy delivered and related capacity payments. This lease revenue is eliminated in our consolidated revenues. Significant Judgments and Estimates TCJA Revenue Reserve The TCJA or “tax reform” signed into law on December 22, 2017, reduced the federal corporate income tax rate from 35% to 21% effective for tax years beginning after December 31, 2017. Black Hills has been collaborating with utility commissions in the states in which it provides utility service to deliver to customers the benefits of a lower corporate federal income tax rate beginning in 2018 with the passage of the TCJA. We estimated and recorded a reserve to revenue of approximately $8.0 million and $23 million during the three and six months ended June 30, 2018 , respectively. As of June 30, 2018 , $3.3 million has been returned to customers and approximately $19 million remains in reserve. Unbilled Revenue Revenues attributable to natural gas and electricity delivered to customers but not yet billed are estimated and accrued, and the related costs are charged to expense. Factors influencing the determination of unbilled revenues include estimates of delivered sales volumes based on weather information and customer consumption trends. Contract Balances The nature of our primary revenue contracts provides an unconditional right to consideration upon service delivery; therefore, no customer contract assets or liabilities exist. The unconditional right to consideration is represented by the balance in our Accounts Receivable further discussed in Note 4. We do not typically incur costs that would be capitalized to obtain or fulfill a contract. Practical Expedients Our revenue contracts generally provide for performance obligations that are fulfilled and transfer control to customers over time, represent a series of distinct services that are substantially the same, involve the same pattern of transfer to the customer, and provide a right to consideration from our customers in an amount that corresponds directly with the value to the customer for the performance completed to date. Therefore, we recognize revenue in the amount to which we have a right to invoice. We have revenue contract performance obligations with similar characteristics, and we reasonably expect that the financial statement impact of applying the new revenue recognition guidance to a portfolio of contracts would not differ materially from applying this guidance to the individual contracts or performance obligations within the portfolio. Therefore, we have elected the portfolio approach in applying the new revenue guidance.

Business Segment Information_

Business Segment Information:	6 Months Ended
	Jun. 30, 2018
Segment Reporting Information, Additional Information [Abstract]
Business Segment Information	BUSINESS SEGMENT INFORMATION Segment information and Corporate and Other included in the accompanying Condensed Consolidated Statements of Income were as follows (in thousands): Three Months Ended June 30, 2018 External Operating Revenue Inter-company Operating Revenue Total Revenues Net income (loss) from continuing operations Contract Customers Other Revenues Contract Customers Other Revenues Segment: Electric $ 166,565 $ 1,754 $ 5,297 $ — $ 173,616 $ 21,890 Gas 176,399 912 309 — 177,620 (1,161 ) Power Generation (b) 1,130 348 11,613 8,793 21,884 4,772 Mining 8,367 229 7,978 325 16,899 3,005 Corporate and Other — — — — — (4,162 ) Inter-company eliminations — — (25,197 ) (9,118 ) (34,315 ) — Total $ 352,461 $ 3,243 $ — $ — $ 355,704 $ 24,344 Under our modified retrospective adoption of ASU 2014-09, revenues for the three and six months ended June 30, 2017 are not presented by contract type. Three Months Ended June 30, 2017 External Operating Revenue Inter-company Operating Revenue Net income (loss) from continuing operations Segment: Electric . $ 165,517 $ 2,936 $ 18,832 Gas 166,439 8 (272 ) Power Generation (b) 1,470 20,325 5,332 Mining 8,403 6,543 2,681 Corporate and Other — — (3,762 ) Inter-company eliminations — (29,812 ) — Total $ 341,829 $ — $ 22,811 Six Months Ended June 30, 2018 External Operating Revenue Inter-company Operating Revenue Total Revenues Net income (loss) from continuing operations Contract Customers Other Revenues Contract Customers Other Revenues Segment: Electric $ 333,743 $ 1,987 $ 11,441 $ — $ 347,171 $ 41,735 Gas (a) 572,141 2,096 727 — 574,964 106,459 Power Generation (b) 2,850 718 23,826 17,593 44,987 10,628 Mining 17,082 476 15,820 649 34,027 5,989 Corporate and Other — — — — — (5,120 ) Inter-company eliminations — — (51,814 ) (18,242 ) (70,056 ) — Total $ 925,816 $ 5,277 $ — $ — $ 931,093 $ 159,691 Six Months Ended June 30, 2017 External Operating Revenue Inter-company Operating Revenue Net income (loss) from continuing operations Segment: Electric $ 337,687 $ 6,790 $ 41,062 Gas 531,340 17 45,738 Power Generation (b) 3,572 41,790 11,862 Mining 16,758 14,734 5,571 Corporate and Other (c) — — (3,330 ) Inter-company eliminations — (63,331 ) — Total $ 889,357 $ — $ 100,903 ___________ (a) Net income from continuing operations available for common stock for the six months ended June 30, 2018 included a $49 million tax benefit resulting from legal entity restructuring. See Note 19 Income Taxes of the Notes to Condensed Consolidated Financial Statements for more information. (b) Net income from continuing operations available for common stock for the three and six months ended June 30, 2018 and June 30, 2017 reflects net income attributable to noncontrolling interests of $2.8 million and $6.5 million , and $3.1 million and $6.6 million , respectively. (c) Net income (loss) from continuing operations available for common stock for the six months ended June 30, 2017 included a $1.4 million tax benefit recognized from carryback claims for specified liability losses involving prior tax years. Segment information and Corporate balances included in the accompanying Condensed Consolidated Balance Sheets were as follows (in thousands): Total Assets (net of inter-company eliminations) as of: June 30, 2018 December 31, 2017 June 30, 2017 Segment: Electric (a) $ 2,902,925 $ 2,906,275 $ 2,901,570 Gas 3,367,247 3,426,466 3,242,461 Power Generation (a) 49,628 60,852 66,292 Mining 68,154 65,455 67,365 Corporate and Other 178,618 115,612 109,581 Discontinued operations 3,557 84,242 122,477 Total assets $ 6,570,129 $ 6,658,902 $ 6,509,746 __________ (a) The PPA under which Black Hills Colorado IPP provides generation to support Colorado Electric customers from the Pueblo Airport Generation Station is accounted for as a capital lease. As such, assets owned by our Power Generation segment are recorded at Colorado Electric under accounting for a capital lease.

Accounts Receivable_

Accounts Receivable:	6 Months Ended
	Jun. 30, 2018
Receivables [Abstract]
Accounts Receivable	ACCOUNTS RECEIVABLE Following is a summary of Accounts receivable, net included in the accompanying Condensed Consolidated Balance Sheets (in thousands) as of: Accounts Unbilled Less Allowance for Accounts June 30, 2018 Receivable, Trade Revenue Doubtful Accounts Receivable, net Electric Utilities $ 44,577 $ 34,940 $ (503 ) $ 79,014 Gas Utilities 70,244 23,557 (3,517 ) 90,284 Power Generation 1,681 — — 1,681 Mining 3,158 — — 3,158 Corporate 1,475 — — 1,475 Total $ 121,135 $ 58,497 $ (4,020 ) $ 175,612 Accounts Unbilled Less Allowance for Accounts December 31, 2017 Receivable, Trade Revenue Doubtful Accounts Receivable, net Electric Utilities $ 39,347 $ 36,384 $ (586 ) $ 75,145 Gas Utilities 81,256 88,967 (2,495 ) 167,728 Power Generation 1,196 — — 1,196 Mining 2,804 — — 2,804 Corporate 1,457 — — 1,457 Total $ 126,060 $ 125,351 $ (3,081 ) $ 248,330 Accounts Unbilled Less Allowance for Accounts June 30, 2017 Receivable, Trade Revenue Doubtful Accounts Receivable, net Electric Utilities $ 41,635 $ 33,686 $ (466 ) $ 74,855 Gas Utilities 62,908 26,584 (2,535 ) 86,957 Power Generation 877 — — 877 Mining 2,904 — — 2,904 Corporate 1,167 — — 1,167 Total $ 109,491 $ 60,270 $ (3,001 ) $ 166,760

Regulatory Accounting_

Regulatory Accounting:	6 Months Ended
	Jun. 30, 2018
Regulatory Assets and Liabilities Disclosure [Abstract]
Regulatory Accounting	REGULATORY ACCOUNTING We had the following regulatory assets and liabilities (in thousands) as of: Maximum Amortization (in years) June 30, 2018 December 31, 2017 June 30, 2017 Regulatory assets Deferred energy and fuel cost adjustments (a) 1 $ 26,725 $ 20,187 $ 20,761 Deferred gas cost adjustments (a) 1 962 31,844 8,962 Gas price derivatives (a) 3 9,120 11,935 11,159 Deferred taxes on AFUDC (b) (f) 45 7,813 7,847 15,322 Employee benefit plans (c) 12 108,366 109,235 107,419 Environmental (a) subject to approval 1,000 1,031 1,070 Asset retirement obligations (a) 44 523 517 510 Loss on reacquired debt (a) 28 19,868 20,667 21,466 Renewable energy standard adjustment (a) subject to approval 1,179 1,088 768 Deferred taxes on flow through accounting (c) (f) 54 28,193 26,978 40,586 Decommissioning costs 10 11,806 13,287 14,681 Gas supply contract termination (a) 4 17,171 20,001 22,793 Other regulatory assets (a) 30 27,976 32,837 31,663 Total regulatory assets 260,702 297,454 297,160 Less current regulatory assets (50,565 ) (81,016 ) (53,061 ) Regulatory assets, non-current $ 210,137 $ 216,438 $ 244,099 Regulatory liabilities Deferred energy and gas costs (a) 1 $ 27,188 $ 3,427 $ 13,693 Employee benefit plan costs and related deferred taxes (c) (f) 12 39,820 40,629 67,297 Cost of removal (a) 44 141,954 130,932 125,598 Excess deferred income taxes (c) (d) 40 310,132 301,553 56 TCJA revenue reserve (e) subject to approval 19,312 — — Other regulatory liabilities (c) 25 11,625 8,585 9,666 Total regulatory liabilities 550,031 485,126 216,310 Less current regulatory liabilities (52,102 ) (6,832 ) (17,305 ) Regulatory liabilities, non-current $ 497,929 $ 478,294 $ 199,005 __________ (a) Recovery of costs, but we are not allowed a rate of return. (b) In addition to recovery of costs, we are allowed a rate of return. (c) In addition to recovery or repayment of costs, we are allowed a return on a portion of this amount or a reduction in rate base. (d) The increase in the regulatory tax liability is primarily related to the revaluation of deferred income tax balances at the lower income tax rate. As of June 30, 2018 and December 31, 2017, all of the liability was classified as non-current due to uncertainties around the timing and other regulatory decisions that will affect the amount of regulatory tax liability amortized and returned to customers through rate reductions of other revenue offsets in 2018. (e) As of June 30, 2018, the amortization periods are yet to be determined and subject to approval by our regulators. (f) The variance to the prior periods is primarily due to the TCJA. Regulatory Matters Except as discussed below, there have been no other significant changes to our Regulatory Matters from those previously disclosed in Note 13 of the Notes to the Consolidated Financial Statements in our 2017 Annual Report on Form 10-K. TCJA revenue reserve - The TCJA signed into law on December 22, 2017, reduced the federal corporate income tax rate from 35% to 21%. Effective January 1, 2018, the key impact of tax reform on existing utility revenues/tariffs established prior to tax reform results primarily from the change in the federal tax rate from 35% to 21% (including the effects of tax gross-ups not yet approved) affecting current income tax expense embedded in those tariffs. Black Hills has been collaborating with utility commissions in the states in which it provides utility service to deliver to customers the benefits of a lower corporate federal income tax rate beginning in 2018 with the passage of the TCJA. We have now received state utility commission approvals to provide the benefits of federal tax reform to utility customers in four states. Discussions are underway with utility commissions in the remaining states and final approval is expected prior to year-end. We estimated and recorded a reserve to revenue of approximately $8.0 million and $23 million during the three and six months ended June 30, 2018 , respectively. As of June 30, 2018 , $3.3 million has been returned to customers. A list of states where benefits to customers of federal tax reform have been approved is summarized below. State Approximate Annual Benefit for Customers Start Date for Customer Benefits Colorado $ 10.8 million July 2018 Iowa $ 2.2 million June 2018 Kansas $ 1.9 million April 2018 Nebraska $ 3.8 million July 2018 In support of returning benefits to customers, the three rate review requests filed in late 2017 for Arkansas Gas, Wyoming Gas (Northwest Wyoming) and Rocky Mountain Natural Gas (a pipeline system in Colorado) were adjusted to include the benefits to customers of federal tax reform as discussed below. Rate Reviews - In Colorado, new rates for RMNG went into effect June 1, 2018 after an administrative law judge recommended approval of a settlement agreement and the CPUC took no further action. The settlement included $1.1 million in annual revenue increases and an extension of SSIR to recover costs from 2018 through December 31, 2021. The annual increase is based on a return on equity of 9.9% and a capital structure of 46.63% equity and 53.37% debt. On July 16, 2018, the WPSC reached a bench decision approving our Wyoming Gas (Northwest Wyoming) settlement and stipulation with the OCA. We expect the final order in the third quarter of 2018. The settlement provides for $1.0 million of new revenue, a return on equity of 9.6% , and a capital structure of 54.0% equity and 46.0% debt. New rates, inclusive of customer benefits related to the TCJA, will be effective September 1, 2018. An Arkansas rate review was filed in December 2017 with the APSC requesting $30 million of annual revenue to recover more than $160 million of new infrastructure investment. The revenue request was subsequently adjusted to $19 million primarily related to a lower corporate income tax rate of 21% . The APSC previously issued a procedural schedule for the rate review. To date, testimony has been filed by the intervenors and Arkansas Gas filed rebuttal testimony on June 26, 2018. The APSC issued an order on July 26 requiring investor owned utilities to provide within 30 days their plans to return tax reform benefits to customers. Arkansas Gas is reviewing the order and its impacts to customers and may amend its current rate review if necessary. A final order and new rates are expected to be effective in the fourth quarter of 2018.

Materials, Supplies and Fuel_

Materials, Supplies and Fuel:	6 Months Ended
	Jun. 30, 2018
Inventory, Net [Abstract]
Materials, Supplies and Fuel	MATERIALS, SUPPLIES AND FUEL The following amounts by major classification are included in Materials, supplies and fuel in the accompanying Condensed Consolidated Balance Sheets (in thousands) as of: June 30, 2018 December 31, 2017 June 30, 2017 Materials and supplies $ 73,075 $ 69,732 $ 68,759 Fuel - Electric Utilities 2,821 2,962 3,106 Natural gas in storage held for distribution 19,558 40,589 23,623 Total materials, supplies and fuel $ 95,454 $ 113,283 $ 95,488

Investments_

Investments:	6 Months Ended
	Jun. 30, 2018
Long-term Investments [Abstract]
Investments	INVESTMENTS In February 2018, we contributed $28 million of assets in exchange for equity securities in a privately held company. The carrying value of our investment in the equity securities was determined using the cost method. We review this investment on a periodic basis to determine whether a significant event or change in circumstances has occurred that may have an adverse effect on the value of the investment. We estimate that the fair value of this cost method investment approximated or exceeded its carrying value as of June 30, 2018 . The following table presents the carrying value of our investments (in thousands) as of: June 30, 2018 December 31, 2017 June 30, 2017 Cost method investment $ 28,134 $ — $ — Cash surrender value of life insurance contracts 13,014 13,090 12,761 Total investments $ 41,148 $ 13,090 $ 12,761

Earnings Per Share_

Earnings Per Share:	6 Months Ended
	Jun. 30, 2018
Earnings Per Share [Abstract]
Earnings Per Share	EARNINGS PER SHARE A reconciliation of share amounts used to compute Earnings (loss) per share in the accompanying Condensed Consolidated Statements of Income was as follows (in thousands): Three Months Ended June 30, Six Months Ended June 30, 2018 2017 2018 2017 Net income available for common stock $ 21,917 $ 22,195 $ 154,921 $ 98,718 Weighted average shares - basic 53,355 53,229 53,337 53,191 Dilutive effect of: Equity Units (a) 1,057 1,977 904 1,796 Equity compensation 108 178 120 192 Weighted average shares - diluted 54,520 55,384 54,361 55,179 __________ (a) Calculated using the treasury stock method. The following outstanding securities were excluded in the computation of diluted net income (loss) per share as their inclusion would have been anti-dilutive (in thousands): Three Months Ended June 30, Six Months Ended June 30, 2018 2017 2018 2017 Equity compensation 15 — 17 — Anti-dilutive shares 15 — 17 —

Notes Payable, Current Maturiti

Notes Payable, Current Maturities and Debt:	6 Months Ended
	Jun. 30, 2018
Debt Disclosure [Abstract]
Notes Payable and Long-term Debt	NOTES PAYABLE, CURRENT MATURITIES AND DEBT We had the following notes payable outstanding in the accompanying Condensed Consolidated Balance Sheets (in thousands) as of: June 30, 2018 December 31, 2017 June 30, 2017 Balance Outstanding Letters of Credit Balance Outstanding Letters of Credit Balance Outstanding Letters of Credit Revolving Credit Facility $ — $ 11,448 $ — $ 26,848 $ — $ 24,540 CP Program 121,800 — 211,300 — 107,975 — Total $ 121,800 $ 11,448 $ 211,300 $ 26,848 $ 107,975 $ 24,540 Revolving Credit Facility and CP Program On July 30, 2018, we amended and restated our corporate Revolving Credit Facility, maintaining total commitments of $750 million and extending the term through July 30, 2023 with two one -year extension options (subject to consent from lenders). This facility is similar to the former revolving credit facility, which includes an accordion feature that allows us, with the consent of the administrative agent, the issuing agents and each bank increasing or providing a new commitment, to increase total commitments up to $1.0 billion . Borrowings continue to be available under a base rate or various Eurodollar rate options. The interest costs associated with the letters of credit or borrowings and the commitment fee under the Revolving Credit Facility are determined based upon our Corporate credit rating from S&P, Fitch, and Moody's for our senior unsecured long-term debt. Based on our credit ratings, the margins for base rate borrowings, Eurodollar borrowings, and letters of credit were 0.250% , 1.250% , and 1.250% , respectively, at June 30, 2018 and are unchanged under our amended and restated Revolving Credit Facility. Based on our credit ratings, a 0.200% commitment fee was charged on the unused amount at June 30, 2018. This commitment fee requirement is unchanged under our amended and restated Revolving Credit Facility. We have a $750 million , unsecured CP Program that is backstopped by the Revolving Credit Facility. Amounts outstanding under the Revolving Credit Facility and the CP Program, either individually or in the aggregate, cannot exceed $750 million . The notes issued under the CP Program may have maturities not to exceed 397 days from the date of issuance and bear interest (or are sold at par less a discount representing an interest factor) based on, among other things, the size and maturity date of the note, the frequency of the issuance and our credit ratings. Under the CP Program, any borrowings rank equally with our unsecured debt. Notes under the CP Program are not registered and are offered and issued pursuant to a registration exemption. Our net payments under the CP Program during the six months ended June 30, 2018 were $90 million and our notes outstanding as of June 30, 2018 were $122 million . As of June 30, 2018 , the weighted average interest rate on CP Program borrowings was 2.29% . Debt Covenants Under our Revolving Credit Facility and term loan agreement (before each was amended and restated), we were required to maintain a Consolidated Indebtedness to Capitalization Ratio not to exceed 0.65 to 1.00 . At June 30, 2018, our Consolidated Indebtedness to Capitalization Ratio was calculated by dividing (i) Consolidated Indebtedness (which included letters of credit and certain guarantees issued but excluded the RSNs), by (ii) Capital, which is Consolidated Indebtedness plus Consolidated Net Worth (which excluded noncontrolling interests in subsidiaries and included the aggregate outstanding amount of the RSNs). Under our amended and restated revolving Credit Facility and amended and restated term loan agreement, we are also required to maintain a Consolidated Indebtedness to Capitalization Ratio not to exceed 0.65 to 1.00 , but as of September 30, 2018 only, Consolidated Net Worth will include the amount receivable by the Company in connection with the common stock settlement under the purchase contracts which are part of the Equity Units, rather than the outstanding amount of the RSNs. Our Revolving Credit Facility and term loans require compliance with the following financial covenant at the end of each quarter: As of June 30, 2018 Covenant Requirement Consolidated Indebtedness to Capitalization Ratio 58% Less than 65% As of June 30, 2018 , we were in compliance with this covenant. Current Maturities As of June 30, 2018 , our $250 million Senior unsecured notes due January 11, 2019 and $5.7 million of principal due in the next twelve months on our Corporate term loan due June 7, 2021 are classified as Current maturities of long-term debt on our Condensed Consolidated Balance Sheets. Long-Term Debt On July 30, 2018, we amended and restated our unsecured term loan due August 2019. This amended and restated term loan, with $300 million outstanding at June 30, 2018, will now mature on July 30, 2020 and has substantially similar terms and covenants as the amended and restated Revolving Credit Facility. The interest cost associated with this term loan is determined based upon our corporate credit rating from S&P, Fitch, and Moody’s for our Senior unsecured long-term debt. Based on our credit ratings, the margins for base rate borrowings and Eurodollar borrowings were 0.050% and 1.050% , respectively, at June 30, 2018, and are 0.000% and 0.750% , respectively, under our amended and restated Revolving Credit Facility.

Equity_

Equity:	6 Months Ended
	Jun. 30, 2018
Statement of Stockholders' Equity [Abstract]
Equity	EQUITY A summary of the changes in equity is as follows: Six Months Ended June 30, 2018 Total Stockholders’ Equity Noncontrolling Interest Total Equity (in thousands) Balance at December 31, 2017 $ 1,708,974 $ 111,232 $ 1,820,206 Net income (loss) 154,921 6,453 161,374 Other comprehensive income (loss) 2,421 — 2,421 Dividends on common stock (50,879 ) — (50,879 ) Share-based compensation 3,194 — 3,194 Dividend reinvestment and stock purchase plan 219 — 219 Other stock transactions (4 ) — (4 ) Distribution to noncontrolling interest — (9,998 ) (9,998 ) Balance at June 30, 2018 $ 1,818,846 $ 107,687 $ 1,926,533 Six Months Ended June 30, 2017 Total Stockholders’ Equity Noncontrolling Interest Total Equity (in thousands) Balance at December 31, 2016 $ 1,614,639 $ 115,495 $ 1,730,134 Net income (loss) 98,718 6,632 105,350 Other comprehensive income (loss) 1,942 — 1,942 Dividends on common stock (47,544 ) — (47,544 ) Share-based compensation 4,133 — 4,133 Dividend reinvestment and stock purchase plan 1,530 — 1,530 Redeemable noncontrolling interest (886 ) — (886 ) Cumulative effect of ASU 2016-09 implementation 3,714 — 3,714 Other stock transactions (7 ) — (7 ) Distribution to noncontrolling interest — (8,335 ) (8,335 ) Balance at June 30, 2017 $ 1,676,239 $ 113,792 $ 1,790,031 At-the-Market Equity Offering Program On August 4, 2017, we renewed our ATM equity offering program which reset the size of the program to an aggregate value of up to $300 million . The renewed program, which allows us to sell shares of our common stock, is the same as the prior program other than the aggregate value increased from $200 million to $300 million . The shares may be offered from time to time pursuant to a sales agreement dated August 4, 2017. Shares of common stock are offered pursuant to our shelf registration statement filed with the SEC. We did not issue any common shares during the six months ended June 30, 2018 and June 30, 2017 under the ATM equity offering program. Noncontrolling Interest Colorado IPP owns a 200 MW , combined-cycle natural gas generating facility located in Pueblo, Colorado. On April 14, 2016, Black Hills Electric Generation sold a 49.9% , noncontrolling interest in Colorado IPP to a third-party buyer. Black Hills Electric Generation is the operator of the facility, which is contracted to provide capacity and energy through 2031 to Black Hills Colorado Electric. Colorado IPP has been determined to be a variable interest entity (VIE) in which the Company has a variable interest. Black Hills Electric Generation has been determined to be the primary beneficiary of the VIE as Black Hills Electric Generation is the operator and manager of the generation facility and, as such, has the power to direct the activities that most significantly impact Colorado IPP’s economic performance. Black Hills Electric Generation, as the primary beneficiary, continues to consolidate Colorado IPP. Colorado IPP has not received financial or other support from the Company outside of pre-existing contractual arrangements during the reporting period. Colorado IPP does not have any debt and its cash flows from operations are sufficient to support its ongoing operations. We have recorded the following assets and liabilities on our Condensed Consolidated Balance Sheets related to the VIE described above as of: June 30, 2018 December 31, 2017 June 30, 2017 (in thousands) Assets Current assets $ 11,462 $ 14,837 $ 12,042 Property, plant and equipment of variable interest entities, net $ 203,308 $ 208,595 $ 214,239 Liabilities Current liabilities $ 2,946 $ 4,565 $ 2,651

Risk Management Activities_

Risk Management Activities:	6 Months Ended
	Jun. 30, 2018
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Risk Management Activities	RISK MANAGEMENT ACTIVITIES Our activities in the regulated and non-regulated energy sectors expose us to a number of risks in the normal operation of our businesses. Depending on the activity, we are exposed to varying degrees of market risk and credit risk. To manage and mitigate these identified risks, we have adopted the Black Hills Corporation Risk Policies and Procedures as discussed in our 2017 Annual Report on Form 10-K. Market Risk Market risk is the potential loss that might occur as a result of an adverse change in market price or rate. We are exposed to the following market risks including, but not limited to: • Commodity price risk associated with our retail natural gas marketing activities and our fuel procurement for certain gas-fired generation assets; and • Interest rate risk associated with our variable rate debt. Credit Risk Credit risk is the risk of financial loss resulting from non-performance of contractual obligations by a counterparty. For production and generation activities, we attempt to mitigate our credit exposure by conducting business primarily with high credit quality entities, setting tenor and credit limits commensurate with counterparty financial strength, obtaining master netting agreements, and mitigating credit exposure with less creditworthy counterparties through parental guarantees, prepayments, letters of credit, and other security agreements. We perform ongoing credit evaluations of our customers and adjust credit limits based on payment history and the customer’s current creditworthiness, as determined by review of their current credit information. We maintain a provision for estimated credit losses based upon historical experience and any specific customer collection issue that is identified. Our derivative and hedging activities recorded in the accompanying Condensed Consolidated Balance Sheets, Condensed Consolidated Statements of Income and Condensed Consolidated Statements of Comprehensive Income are detailed below and in Note 12 . Utilities The operations of our utilities, including natural gas sold by our Gas Utilities and natural gas used by our Electric Utilities’ generation plants or those plants under PPAs where our Electric Utilities must provide the generation fuel (tolling agreements), expose our utility customers to volatility in natural gas prices. Therefore, as allowed or required by state utility commissions, we have entered into commission-approved hedging programs utilizing natural gas futures, options, over-the-counter swaps and basis swaps to reduce our customers’ underlying exposure to these fluctuations. These transactions are considered derivatives, and in accordance with accounting standards for derivatives and hedging, mark-to-market adjustments are recorded as Derivative assets or Derivative liabilities on the accompanying Condensed Consolidated Balance Sheets, net of balance sheet offsetting as permitted by GAAP. For our regulated utilities’ hedging plans, unrealized and realized gains and losses, as well as option premiums and commissions on these transactions are recorded as Regulatory assets or Regulatory liabilities in the accompanying Condensed Consolidated Balance Sheets in accordance with state commission guidelines. When the related costs are recovered through our rates, the hedging activity is recognized in the Condensed Consolidated Statements of Income. We buy, sell and deliver natural gas at competitive prices by managing commodity price risk. As a result of these activities, this area of our business is exposed to risks associated with changes in the market price of natural gas. We manage our exposure to such risks using over-the-counter and exchange traded options and swaps with counterparties in anticipation of forecasted purchases and/or sales during time frames ranging from July 2018 through May 2020. A portion of our over-the-counter swaps have been designated as cash flow hedges to mitigate the commodity price risk associated with forward contracts to deliver gas to our Choice Gas Program customers. The effective portion of the gain or loss on these designated derivatives is reported in AOCI in the accompanying Condensed Consolidated Balance Sheets and the ineffective portion, if any, is reported in Fuel, purchased power and cost of natural gas sold in the accompanying Condensed Consolidated Statements of Income. Effectiveness of our hedging position is evaluated at inception of the hedge, upon occurrence of a triggering event and as of the end of each quarter. The contract or notional amounts and terms of the natural gas derivative commodity instruments held at our utilities are composed of both long and short positions. We were in a net long position as of: June 30, 2018 December 31, 2017 June 30, 2017 Notional (MMBtus) Maximum Term (months) (a) Notional (MMBtus) Maximum Term (months) (a) Notional (MMBtus) Maximum Term (months) (a) Natural gas futures purchased 5,680,000 30 8,330,000 36 11,060,000 42 Natural gas options purchased, net 1,140,000 9 3,540,000 14 1,640,000 20 Natural gas basis swaps purchased 5,720,000 30 8,060,000 36 10,070,000 42 Natural gas over-the-counter swaps, net (b) 4,950,000 23 3,820,000 29 5,200,000 23 Natural gas physical contracts, net (c) 3,866,648 210 12,826,605 35 8,427,119 10 __________ (a) Term reflects the maximum forward period hedged. (b) As of June 30, 2018 , 2,452,000 MMBtus were designated as cash flow hedges for the natural gas over-the-counter swaps purchased. (c) Volumes exclude contracts that qualify for the normal purchase, normal sales exception. Based on June 30, 2018 prices, a $0.1 million loss would be realized, reported in pre-tax earnings and reclassified from AOCI during the next 12 months. As market prices fluctuate, estimated and actual realized gains or losses will change during future periods. We have certain derivative contracts which contain credit provisions. These credit provisions may require the Company to post collateral when credit exposure to the Company is in excess of a negotiated line of unsecured credit. At June 30, 2018 , the Company posted $0.7 million related to such provisions, which is included in Other current assets on the Condensed Consolidated Balance Sheets. Financing Activities At June 30, 2018 , we had no outstanding interest rate swap agreements. Our last interest rate swap agreement with a $50 million notional value, which was designated to borrowings on our Revolving Credit Facility, expired in January 2017. Discontinued Operations Our Oil and Gas segment was exposed to risks associated with changes in the market prices of oil and gas. Through December 2017, we used exchange traded futures, swaps and options to hedge portions of our crude oil and natural gas production to mitigate commodity price risk and preserve cash flows. Hedge accounting was elected on the swaps and futures contracts. These transactions were designated upon inception as cash flow hedges, documented under accounting standards for derivatives and hedging and initially met prospective effectiveness testing. As a result of divesting our Oil and Gas assets, these activities were discontinued and there were no outstanding derivative agreements as of June 30, 2018 or December 31, 2017 . At June 30, 2017, we had outstanding crude oil futures and swap contracts with notional volumes of 72,000 Bbls, crude oil option contracts with notional volumes of 18,000 Bbls and natural gas futures and swap contracts with notional volumes of 1,080,000 MMBtus. Cash Flow Hedges The impacts of cash flow hedges on our Condensed Consolidated Statements of Income is presented below for the three and six months ended June 30, 2018 and 2017 (in thousands). Note that this presentation does not reflect gains or losses arising from the underlying physical transactions; therefore, it is not indicative of the economic profit or loss we realized when the underlying physical and financial transactions were settled. Three Months Ended June 30, 2018 Derivatives in Cash Flow Hedging Relationships Location of Reclassifications from AOCI into Income Amount of Gain/(Loss) Reclassified from AOCI into Income (Settlements) Location of Gain/(Loss) Recognized in Income on Derivative (Ineffective Portion) Amount of Gain/(Loss) Recognized in Income on Derivative (Ineffective Portion) Interest rate swaps Interest expense $ (713 ) Interest expense $ — Commodity derivatives Fuel, purchased power and cost of natural gas sold (163 ) Fuel, purchased power and cost of natural gas sold — Total $ (876 ) $ — Three Months Ended June 30, 2017 Derivatives in Cash Flow Hedging Relationships Location of Reclassifications from AOCI into Income Amount of Gain/(Loss) Reclassified from AOCI into Income (Settlements) Location of Gain/(Loss) Recognized in Income on Derivative (Ineffective Portion) Amount of Gain/(Loss) Recognized in Income on Derivative (Ineffective Portion) Interest rate swaps Interest expense $ (713 ) Interest expense $ — Commodity derivatives Net (loss) from discontinued operations 430 Net (loss) from discontinued operations — Commodity derivatives Fuel, purchased power and cost of natural gas sold (44 ) Fuel, purchased power and cost of natural gas sold — Total $ (327 ) $ — Six Months Ended June 30, 2018 Derivatives in Cash Flow Hedging Relationships Location of Reclassifications from AOCI into Income Amount of Gain/(Loss) Reclassified from AOCI into Income (Settlements) Location of Gain/(Loss) Recognized in Income on Derivative (Ineffective Portion) Amount of Gain/(Loss) Recognized in Income on Derivative (Ineffective Portion) Interest rate swaps Interest expense $ (1,426 ) Interest expense $ — Commodity derivatives Fuel, purchased power and cost of natural gas sold (784 ) Fuel, purchased power and cost of natural gas sold — Total $ (2,210 ) $ — Six Months Ended June 30, 2017 Derivatives in Cash Flow Hedging Relationships Location of Reclassifications from AOCI into Income Amount of Gain/(Loss) Reclassified from AOCI into Income (Settlements) Location of Gain/(Loss) Recognized in Income on Derivative (Ineffective Portion) Amount of Gain/(Loss) Recognized in Income on Derivative (Ineffective Portion) Interest rate swaps Interest expense $ (1,515 ) Interest expense $ — Commodity derivatives Net (loss) from discontinued operations 659 Net (loss) from discontinued operations — Commodity derivatives Fuel, purchased power and cost of natural gas sold 14 Fuel, purchased power and cost of natural gas sold — Total $ (842 ) $ — The following tables summarize the gains and losses arising from hedging transactions that were recognized as a component of other comprehensive income (loss) for the three and six months ended June 30, 2018 and 2017 . The amounts included in the tables below exclude gains and losses arising from ineffectiveness because these amounts, if any, are immediately recognized in the Condensed Consolidated Statements of Income as incurred. Three Months Ended June 30, 2018 2017 (in thousands) Increase (decrease) in fair value: Forward commodity contracts $ 48 $ 525 Recognition of (gains) losses in earnings due to settlements: Interest rate swaps 713 713 Forward commodity contracts 163 (386 ) Total other comprehensive income (loss) from hedging $ 924 $ 852 Six Months Ended June 30, 2018 2017 (in thousands) Increase (decrease) in fair value: Forward commodity contracts $ (249 ) $ 1,451 Recognition of (gains) losses in earnings due to settlements: Interest rate swaps 1,426 1,515 Forward commodity contracts 784 (673 ) Total other comprehensive income (loss) from hedging $ 1,961 $ 2,293 Derivatives Not Designated as Hedge Instruments The following table summarizes the impacts of derivative instruments not designated as hedge instruments on our Condensed Consolidated Statements of Income for the three and six months ended June 30, 2018 and 2017 (in thousands). Note that this presentation does not reflect gains or losses arising from the underlying physical transactions; therefore, it is not indicative of the economic profit or loss we realized when the underlying physical and financial transactions were settled. Three Months Ended June 30, 2018 2017 Derivatives Not Designated as Hedging Instruments Location of Gain/(Loss) on Derivatives Recognized in Income Amount of Gain/(Loss) on Derivatives Recognized in Income Amount of Gain/(Loss) on Derivatives Recognized in Income Commodity derivatives Net (loss) from discontinued operations $ — $ 26 Commodity derivatives Fuel, purchased power and cost of natural gas sold 771 (691 ) $ 771 $ (665 ) Six Months Ended June 30, 2018 2017 Derivatives Not Designated as Hedging Instruments Location of Gain/(Loss) on Derivatives Recognized in Income Amount of Gain/(Loss) on Derivatives Recognized in Income Amount of Gain/(Loss) on Derivatives Recognized in Income Commodity derivatives Net (loss) from discontinued operations $ — $ 143 Commodity derivatives Fuel, purchased power and cost of natural gas sold 1,025 (1,500 ) $ 1,025 $ (1,357 ) As discussed above, financial instruments used in our regulated utilities are not designated as cash flow hedges. However, there is no earnings impact because the unrealized gains and losses arising from the use of these financial instruments are recorded as Regulatory assets or Regulatory liabilities. The net unrealized losses included in our Regulatory assets or Regulatory liability accounts related to the hedges in our utilities were $9.1 million , $12 million and $11 million at June 30, 2018 , December 31, 2017 and June 30, 2017 , respectively.

Fair Value Measurements_

Fair Value Measurements:	6 Months Ended
	Jun. 30, 2018
Fair Value Disclosures [Abstract]
Fair Value Measurements	FAIR VALUE MEASUREMENTS Derivative Financial Instruments The accounting guidance for fair value measurements requires certain disclosures about assets and liabilities measured at fair value. This guidance establishes a hierarchical framework for disclosing the observability of the inputs utilized in measuring assets and liabilities at fair value. Assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. Our assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the placement within the fair value hierarchy levels. We record transfers, if necessary, between levels at the end of the reporting period for all of our financial instruments. For additional information, see Notes 1, 9, 10 and 11 to the Consolidated Financial Statements included in our 2017 Annual Report on Form 10-K filed with the SEC. Transfers into Level 3, if any, occur when significant inputs used to value the derivative instruments become less observable such as a significant decrease in the frequency and volume in which the instrument is traded, negatively impacting the availability of observable pricing inputs. Transfers out of Level 3, if any, occur when the significant inputs become more observable, such as when the time between the valuation date and the delivery date of a transaction becomes shorter, positively impacting the availability of observable pricing inputs. Valuation Methodologies for Derivatives Discontinued Operations: • Oil and gas derivative instruments are included in assets and liabilities held for sale discussed in Note 18. Utilities Segments: • The commodity contracts for our Utilities Segments, are valued using the market approach and include exchange-traded futures, options, basis swaps and over-the-counter swaps and options (Level 2) for natural gas contracts. For exchange-traded futures, options and basis swap assets and liabilities, fair value was derived using broker quotes validated by the exchange settlement pricing for the applicable contract. For over-the-counter instruments, the fair value is obtained by utilizing a nationally recognized service that obtains observable inputs to compute the fair value, which we validate by comparing our valuation with the counterparty. The fair value of these swaps includes a CVA component based on the credit spreads of the counterparties when we are in an unrealized gain position or on our own credit spread when we are in an unrealized loss position. Corporate Activities: • As of June 30, 2018 , we no longer have derivatives within our corporate activities as our last interest rate swaps matured in January 2017. Recurring Fair Value Measurements There have been no significant transfers between Level 1 and Level 2 derivative balances. Amounts included in cash collateral and counterparty netting in the following tables represent the impact of legally enforceable master netting agreements that allow us to settle positive and negative positions, netting of asset and liability positions permitted in accordance with accounting standards for offsetting as well as cash collateral posted with the same counterparties. Oil and gas derivative instruments are included in assets and liabilities held for sale discussed in Note 18. The following tables set forth by level within the fair value hierarchy present gross assets and gross liabilities and related offsetting cash collateral and counterparty netting as permitted by GAAP that were accounted for at fair value on a recurring basis for derivative instruments. As of June 30, 2018 Level 1 Level 2 Level 3 Cash Collateral and Counterparty Netting Total (in thousands) Assets: Commodity derivatives — Utilities $ — $ 1,035 $ — $ (363 ) $ 672 Total $ — $ 1,035 $ — $ (363 ) $ 672 Liabilities: Commodity derivatives — Utilities $ — $ 9,808 $ — $ (9,144 ) $ 664 Total $ — $ 9,808 $ — $ (9,144 ) $ 664 As of December 31, 2017 Level 1 Level 2 Level 3 Cash Collateral and Counterparty Netting Total (in thousands) Assets: Commodity derivatives — Utilities $ — $ 1,586 $ — $ (1,282 ) $ 304 Total $ — $ 1,586 $ — $ (1,282 ) $ 304 Liabilities: Commodity derivatives — Utilities $ — $ 13,756 $ — $ (11,497 ) $ 2,259 Total $ — $ 13,756 $ — $ (11,497 ) $ 2,259 As of June 30, 2017 Level 1 Level 2 Level 3 Cash Collateral and Counterparty Netting Total (in thousands) Assets: Commodity derivatives — Utilities $ — $ 1,622 $ — $ (977 ) $ 645 Total $ — $ 1,622 $ — $ (977 ) $ 645 Liabilities: Commodity derivatives — Utilities $ — $ 12,331 $ — $ (11,568 ) $ 763 Total $ — $ 12,331 $ — $ (11,568 ) $ 763 Fair Value Measures by Balance Sheet Classification As required by accounting standards for derivatives and hedges, fair values within the following tables are presented on a gross basis aside from the netting of asset and liability positions permitted in accordance with accounting standards for offsetting and under terms of our master netting agreements and the impact of legally enforceable master netting agreements that allow us to settle positive and negative positions. The following tables present the fair value and balance sheet classification of our derivative instruments (in thousands): As of June 30, 2018 Balance Sheet Location Fair Value of Asset Derivatives Fair Value of Liability Derivatives Derivatives designated as hedges: Commodity derivatives Derivative assets — current $ 128 $ — Commodity derivatives Other assets, non-current 6 — Commodity derivatives Derivative liabilities — current — 305 Commodity derivatives Other deferred credits and other liabilities — 16 Total derivatives designated as hedges $ 134 $ 321 Derivatives not designated as hedges: Commodity derivatives Derivative assets — current $ 538 $ — Commodity derivatives Other assets, non-current — — Commodity derivatives Derivative liabilities — current — 180 Commodity derivatives Other deferred credits and other liabilities — 163 Total derivatives not designated as hedges $ 538 $ 343 As of December 31, 2017 Balance Sheet Location Fair Value of Asset Derivatives Fair Value of Liability Derivatives Derivatives designated as hedges: Commodity derivatives Derivative liabilities — current $ — $ 817 Commodity derivatives Other deferred credits and other liabilities — 67 Total derivatives designated as hedges $ — $ 884 Derivatives not designated as hedges: Commodity derivatives Derivative assets — current $ 304 $ — Commodity derivatives Derivative liabilities — current — 1,264 Commodity derivatives Other deferred credits and other liabilities — 111 Total derivatives not designated as hedges $ 304 $ 1,375 As of June 30, 2017 Balance Sheet Location Fair Value of Asset Derivatives Fair Value of Liability Derivatives Derivatives designated as hedges: Commodity derivatives Derivative assets — current $ 39 $ — Commodity derivatives Current assets held for sale 509 — Commodity derivatives Noncurrent assets held for sale 31 — Commodity derivatives Derivative liabilities — current — 140 Commodity derivatives Other deferred credits and other liabilities — 32 Commodity derivatives Current liabilities held for sale — 27 Total derivatives designated as hedges $ 579 $ 199 Derivatives not designated as hedges: Commodity derivatives Derivative assets — current $ 600 $ — Commodity derivatives Other assets, non-current 6 — Commodity derivatives Derivative liabilities — current — 536 Commodity derivatives Other deferred credits and other liabilities — 55 Commodity derivatives Current liabilities held for sale — 17 Total derivatives not designated as hedges $ 606 $ 608 Fair value measurements also apply to the valuation of our pension and postretirement plan assets. Current accounting guidance requires employers to annually disclose information about the fair value measurements of their assets of a defined benefit pension or other postretirement plan. The fair value of these assets is presented in Note 18 to the Consolidated Financial Statements included in our 2017 Annual Report on Form 10-K.

Fair Value of Financial Instrum

Fair Value of Financial Instruments:	6 Months Ended
	Jun. 30, 2018
Fair Value Disclosures [Abstract]
Fair Value of Financial Instruments	FAIR VALUE OF FINANCIAL INSTRUMENTS The estimated fair values of our financial instruments, excluding derivatives which are presented in Note 12 , were as follows (in thousands) as of: June 30, 2018 December 31, 2017 June 30, 2017 Carrying Amount Fair Value Carrying Amount Fair Value Carrying Amount Fair Value Cash and cash equivalents (a) $ 8,630 $ 8,630 $ 15,420 $ 15,420 $ 11,528 $ 11,528 Restricted cash (a) $ 3,084 $ 3,084 $ 2,820 $ 2,820 $ 2,534 $ 2,534 Notes payable (b) $ 121,800 $ 121,800 $ 211,300 $ 211,300 $ 107,975 $ 107,975 Long-term debt, including current maturities (c) (d) $ 3,113,811 $ 3,234,780 $ 3,115,143 $ 3,350,544 $ 3,166,045 $ 3,377,891 __________ (a) Carrying value approximates fair value due to either the short-term length of maturity or variable interest rates that approximate prevailing market rates, and therefore is classified in Level 1 in the fair value hierarchy. (b) Notes payable consist of commercial paper borrowings and borrowings on our Revolving Credit Facility. Carrying value approximates fair value due to the short-term length of maturity; since these borrowings are not traded on an exchange, they are classified in Level 2 in the fair value hierarchy. (c) Long-term debt is valued based on observable inputs available either directly or indirectly for similar liabilities in active markets and therefore is classified in Level 2 in the fair value hierarchy. (d) Carrying amount of long-term debt is net of deferred financing costs.

Other Comprehensive Income (Los

Other Comprehensive Income (Loss):	6 Months Ended
	Jun. 30, 2018
Statement of Comprehensive Income [Abstract]
Other Comprehensive Income (Loss)	OTHER COMPREHENSIVE INCOME (LOSS) We record deferred gains (losses) in AOCI related to interest rate swaps designated as cash flow hedges, commodity contracts designated as cash flow hedges and the amortization of components of our defined benefit plans. Deferred gains (losses) for our commodity contracts designated as cash flow hedges are recognized in earnings upon settlement, while deferred gains (losses) related to our interest rate swaps are recognized in earnings as they are amortized. The following table details reclassifications out of AOCI and into net income. The amounts in parentheses below indicate decreases to net income in the Condensed Consolidated Statements of Income for the period, net of tax (in thousands): Location on the Condensed Consolidated Statements of Income Amount Reclassified from AOCI Three Months Ended Six Months Ended June 30, 2018 June 30, 2017 June 30, 2018 June 30, 2017 Gains and (losses) on cash flow hedges: Interest rate swaps Interest expense $ (713 ) $ (713 ) $ (1,426 ) $ (1,515 ) Commodity contracts Net (loss) from discontinued operations — 430 — 659 Commodity contracts Fuel, purchased power and cost of natural gas sold (163 ) (44 ) (784 ) 14 (876 ) (327 ) (2,210 ) (842 ) Income tax Income tax benefit (expense) 197 106 494 281 Total reclassification adjustments related to cash flow hedges, net of tax $ (679 ) $ (221 ) $ (1,716 ) $ (561 ) Amortization of components of defined benefit plans: Prior service cost Operations and maintenance $ 44 $ 49 $ 89 $ 97 Actuarial gain (loss) Operations and maintenance (622 ) (414 ) (1,244 ) (828 ) (578 ) (365 ) (1,155 ) (731 ) Income tax Income tax benefit (expense) 126 128 252 265 Total reclassification adjustments related to defined benefit plans, net of tax $ (452 ) $ (237 ) $ (903 ) $ (466 ) Total reclassifications $ (1,131 ) $ (458 ) $ (2,619 ) $ (1,027 ) Balances by classification included within AOCI, net of tax on the accompanying Condensed Consolidated Balance Sheets were as follows (in thousands): Interest Rate Swaps Commodity Derivatives Employee Benefit Plans Total As of December 31, 2017 $ (19,581 ) $ (518 ) $ (21,103 ) $ (41,202 ) Other comprehensive income (loss) before reclassifications — (198 ) — (198 ) Amounts reclassified from AOCI 1,122 594 903 2,619 Reclassifications of certain tax effects from AOCI 15 — 3 18 Ending Balance June 30, 2018 $ (18,444 ) $ (122 ) $ (20,197 ) $ (38,763 ) Interest Rate Swaps Commodity Derivatives Employee Benefit Plans Total Balance as of December 31, 2016 $ (18,109 ) $ (233 ) $ (16,541 ) $ (34,883 ) Other comprehensive income (loss) before reclassifications — 915 — 915 Amounts reclassified from AOCI 985 (424 ) 466 1,027 Ending Balance June 30, 2017 $ (17,124 ) $ 258 $ (16,075 ) $ (32,941 )

Supplemental Disclosure of Cash

Supplemental Disclosure of Cash Flow Information:	6 Months Ended
	Jun. 30, 2018
Supplemental Cash Flow Information [Abstract]
Supplemental Disclosure of Cash Flow Information	SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION Six Months Ended June 30, 2018 June 30, 2017 (in thousands) Non-cash investing and financing activities — Property, plant and equipment acquired with accrued liabilities $ 37,168 $ 31,579 Cash (paid) refunded during the period — Interest (net of amounts capitalized) $ (67,119 ) $ (65,820 ) Income taxes (paid) refunded $ (14,837 ) $ 1

Employee Benefit Plans_

Employee Benefit Plans:	6 Months Ended
	Jun. 30, 2018
Defined Benefit Plan [Abstract]
Employee Benefit Plans	EMPLOYEE BENEFIT PLANS Defined Benefit Pension Plan The components of net periodic benefit cost for the Defined Benefit Pension Plan were as follows (in thousands): Three Months Ended June 30, Six Months Ended June 30, 2018 2017 2018 2017 Service cost $ 1,709 $ 1,759 $ 3,417 $ 3,517 Interest cost 3,868 3,880 7,735 7,760 Expected return on plan assets (6,185 ) (6,129 ) (12,370 ) (12,258 ) Prior service cost 14 15 29 29 Net loss (gain) 2,157 1,001 4,315 2,003 Net periodic benefit cost $ 1,563 $ 526 $ 3,126 $ 1,051 Defined Benefit Postretirement Healthcare Plans The components of net periodic benefit cost for the Defined Benefit Postretirement Healthcare Plans were as follows (in thousands): Three Months Ended June 30, Six Months Ended June 30, 2018 2017 2018 2017 Service cost $ 572 $ 575 $ 1,145 $ 1,150 Interest cost 521 534 1,042 1,067 Expected return on plan assets (56 ) (79 ) (113 ) (158 ) Prior service cost (benefit) (99 ) (109 ) (198 ) (218 ) Net loss (gain) 54 125 108 250 Net periodic benefit cost $ 992 $ 1,046 $ 1,984 $ 2,091 Supplemental Non-qualified Defined Benefit and Defined Contribution Plans The components of net periodic benefit cost for the Supplemental Non-qualified Defined Benefit and Defined Contribution Plans were as follows (in thousands): Three Months Ended June 30, Six Months Ended June 30, 2018 2017 2018 2017 Service cost $ 435 $ 609 $ 715 $ 1,436 Interest cost 292 319 585 638 Prior service cost 1 — 1 1 Net loss (gain) 250 250 500 500 Net periodic benefit cost $ 978 $ 1,178 $ 1,801 $ 2,575 For the three and six months ended June 30, 2018 , service costs were recorded in Operations and maintenance expense while non-service costs were recorded in Other income (expense), net, on the Condensed Consolidated Statements of Income. For the three and six months ended June 30, 2017 , service costs and non-service costs were recorded in Operations and maintenance expense. Because prior years’ costs were not considered material, they were not reclassified on the Condensed Consolidated Statements of Income. See Note 1 for additional information. Contributions Contributions to the Defined Benefit Pension Plan are cash contributions made directly to the Pension Plan Trust account. On July 25, 2018, we made a contribution of approximately $13 million (included in the table below) to the Defined Benefit Pension Plan. Contributions to the Postretirement Healthcare and Supplemental Plans are made in the form of benefit payments. Contributions made in 2018 and anticipated contributions for 2018 and 2019 are as follows (in thousands): Contributions Made Contributions Made Additional Contributions Contributions Three Months Ended June 30, 2018 Six Months Ended June 30, 2018 Anticipated for 2018 Anticipated for 2019 Defined Benefit Pension Plan $ — $ — $ 12,700 $ 12,700 Non-pension Defined Benefit Postretirement Healthcare Plans $ 1,234 $ 2,468 $ 2,468 $ 4,802 Supplemental Non-qualified Defined Benefit and Defined Contribution Plans $ 343 $ 686 $ 686 $ 1,921

Commitments and Contingencies_

Commitments and Contingencies:	6 Months Ended
	Jun. 30, 2018
Commitments and Contingencies Disclosure [Abstract]
Commitments and Contingencies	COMMITMENTS AND CONTINGENCIES There have been no significant changes to commitments and contingencies from those previously disclosed in Note 19 of our Notes to the Consolidated Financial Statements in our 2017 Annual Report on Form 10-K. Dividend Restrictions Our Revolving Credit Facility and other debt obligations contain restrictions on the payment of cash dividends upon a default or event of default. As of June 30, 2018 , we were in compliance with the debt covenants. Due to our holding company structure, substantially all of our operating cash flows are provided by dividends paid or distributions made by our subsidiaries. The cash to pay dividends to our stockholders is derived from these cash flows. As a result, certain statutory limitations or regulatory or financing agreements could affect the levels of distributions allowed to be made by our subsidiaries. Our utilities are generally limited to the amount of dividends allowed to be paid to us as a utility holding company under the Federal Power Act and settlement agreements with state regulatory jurisdictions and financing agreements. As of June 30, 2018 , the restricted net assets at our Electric Utilities and Gas Utilities were approximately $257 million .

Discontinued Operations_

Discontinued Operations:	6 Months Ended
	Jun. 30, 2018
Discontinued Operations and Disposal Groups [Abstract]
Discontinued Operations	DISCONTINUED OPERATIONS Results of operations for discontinued operations have been classified as Loss from discontinued operations, net of income taxes in the accompanying Condensed Consolidated Statements of Income. Current assets, noncurrent assets, current liabilities and non-current liabilities of the discontinued operations have been reclassified and reflected on the accompanying Condensed Consolidated Balance Sheets as “Current assets held for sale,” “Noncurrent assets held for sale,” “Current liabilities held for sale,” and “Noncurrent liabilities held for sale”, respectively. Prior periods relating to our discontinued operations have also been reclassified to reflect consistency within our condensed consolidated financial statements. Oil and Gas Segment On November 1, 2017, the BHC Board of Directors approved a complete divestiture of our Oil and Gas segment. As of June 30, 2018, we have sold nearly all oil and gas assets. Transaction closing for the last few assets and final accounting are expected within the third quarter. The closing of the oil and gas office will occur in August. We expect to transfer any associated liabilities, and settle substantially all remaining liabilities by September 30, 2018. In the process of divesting our Oil and Gas segment, we performed a fair value assessment of the assets and liabilities classified as held for sale. We evaluated our disposal groups classified as held for sale based on the lower of carrying value or fair value less cost to sell. The market approach was based on our recent sales of assets and pending sale transactions of our other properties. There is risk involved when determining the fair value of assets, as there may be unforeseen events and changes in circumstances and market conditions that have a material impact on the estimated amount and timing of future cash flows. In addition, the fair value of the assets and liabilities could be different using different estimates and assumptions in the valuation techniques used. We believe that the estimates used in calculating the fair value of our assets and liabilities held for sale are reasonable based on the information that was known when the estimates were made and how they compared with the additional property sales occurring after December 31, 2017. At December 31, 2017 , the fair value of our held for sale assets was less than our carrying value, which required an after-tax write down of $13 million . There were no further adjustments made to the fair value of our held for sale assets at June 30, 2018 . During the six months ended June 30, 2018 , we recorded $2.2 million of expenses comprised of royalty payments and reclamation costs related to final closing on the sale of BHEP assets, which are presented as Loss on the sale of assets in the table below. Total assets and liabilities of BHEP at June 30, 2018 and December 31, 2017 have been classified as Current assets held for sale and Current liabilities held for sale on the accompanying Condensed Consolidated Balance Sheets due to the expected final disposals occurring by September 30, 2018. Held for sale assets and liabilities at June 30, 2017 are classified as current and non-current (in thousands) as of. June 30, 2018 December 31, 2017 June 30, 2017 Other current assets $ 378 $ 10,360 $ 8,193 Derivative assets, current and noncurrent — — 541 Deferred income tax assets, noncurrent, net — 16,966 20,654 Property, plant and equipment, net 3,179 56,916 93,089 Other current liabilities (4,295 ) (18,966 ) (10,860 ) Derivative liabilities, current and noncurrent — — (44 ) Deferred income tax liabilities, noncurrent, net (1,153 ) — — Other noncurrent liabilities — (22,808 ) (23,048 ) Net assets (liabilities) $ (1,891 ) $ 42,468 $ 88,525 At June 30, 2018 , December 31, 2017 and June 30, 2017 , the Oil and Gas segment’s net deferred tax assets and liabilities were primarily comprised of basis differences on oil and gas properties. BHEP’s other current liabilities at June 30, 2018 consisted primarily of accrued royalties, payroll and property taxes. Current liabilities at December 31, 2017 consisted primarily of a liability contingent on final approval from the Bureau of Indian Affairs on the Jicarilla property sale, accrued royalties, payroll and property taxes. Current liabilities at June 30, 2017 consisted primarily of accrued royalties, payroll and property taxes. Other noncurrent liabilities at December 31, 2017 and June 30, 2017 consisted primarily of asset retirement obligations relating to plugging and abandonment of oil and gas wells. Operating results of the Oil and Gas segment included in Discontinued operations on the accompanying Condensed Consolidated Statements of Income were as follows (in thousands) for the period ended: Three Months Ended June 30, Six Months Ended June 30, 2018 2017 2018 2017 Revenue $ 1,284 $ 6,149 $ 5,199 $ 12,624 Operations and maintenance 2,718 5,491 8,407 12,696 Loss (gain) on sale of assets 1,991 (249 ) 2,203 (249 ) Depreciation, depletion and amortization — 1,838 1,300 3,783 Total operating expenses 4,709 7,080 11,910 16,230 Operating (loss) (3,425 ) (931 ) (6,711 ) (3,606 ) Other income (expense), net 90 65 119 138 Income tax benefit (expense) 908 250 1,822 1,283 (Loss) from discontinued operations $ (2,427 ) $ (616 ) $ (4,770 ) $ (2,185 )

Income Taxes_

Income Taxes:	6 Months Ended
	Jun. 30, 2018
Income Tax Disclosure [Abstract]
Income Taxes	INCOME TAXES The effective tax rate differs from the federal statutory rate as follows: Three Months Ended June 30, Tax (benefit) expense 2018 2017 Federal statutory rate 21.0 % 35.0 % State income tax (net of federal tax effect) 1.7 (0.1 ) Percentage depletion in excess of cost (0.4 ) (1.2 ) Noncontrolling interest (a) (1.0 ) (3.1 ) Tax credits (b) (2.1 ) (3.6 ) Effective tax rate adjustment (c) — 4.4 Flow-through adjustments (0.7 ) (2.6 ) TCJA change in estimate (d) 0.3 — AFUDC equity (0.1 ) (0.6 ) Other tax differences 0.7 0.9 19.4 % 29.1 % __________ (a) The adjustment reflects the non-controlling interest attributable to the sale of 49.9% of the membership interests of COIPP LLC in April 2016. (b) The tax credits are due to the production tax credits for the Peak View wind farm. (c) Adjustment to reflect our projected annual effective tax rate, pursuant to ASC 740-270. (d) The TCJA was signed into law on December 22, 2017. In accordance with ASC 740, net deferred tax assets and liabilities were revalued as of December 31, 2017 due to the reduction in the federal income tax rate from 35% to 21%. During the three months ended June 30, 2018, certain estimated items associated with the revaluation have been updated. Six Months Ended June 30, Tax (benefit) expense 2018 2017 Federal statutory rate 21.0 % 35.0 % State income tax (net of federal tax effect) 1.7 1.0 Percentage depletion in excess of cost (0.4 ) (0.6 ) Noncontrolling interest (1.0 ) (1.6 ) IRC 172(f) carryback claim (a) — (1.3 ) Tax credits (2.1 ) (1.8 ) Effective tax rate adjustment — (0.8 ) Flow-through adjustments (0.7 ) (1.0 ) TCJA change in estimate (b) 1.6 — AFUDC equity (0.1 ) — Jurisdictional simplification project (c) (33.7 ) — Other tax differences 0.6 0.4 (13.1 )% 29.3 % __________ (a) During the first quarter of 2017, the Company filed amended income tax returns for the years 2006 through 2008 to carryback specified liability losses in accordance with IRC172(f). As a result of filing the amended returns, the Company’s accrued tax liability interest decreased, certain valuation allowances increased and the previously recorded domestic production activities deduction decreased. (b) The TCJA was signed into law on December 22, 2017. In accordance with ASC 740, net deferred tax assets and liabilities were revalued as of December 31, 2017 due to the reduction in the federal income tax rate from 35% to 21%. During the six months ended June 30, 2018, certain estimated items associated with the revaluation have been updated. (c) Tax benefit from legal restructuring associated with amortizable goodwill as part of ongoing jurisdictional simplification. Tax benefit related to legal restructuring As part of the Company’s ongoing efforts to continue to integrate the legal entities that the Company has acquired in recent years, certain legal entity restructuring transactions occurred on March 31, 2018. As a result of these transactions, additional deferred income tax assets of $49 million , related to goodwill that is amortizable for tax purposes, were recorded and deferred tax benefits of $49 million were recorded to income tax benefit (expense) on the Condensed Consolidated Statements of Income. Due to this being a common control transaction, it had no effect on the other assets and liabilities of these entities. TCJA On December 22, 2017, the U.S. government enacted comprehensive tax legislation commonly referred to as the TCJA. The TCJA reduced the U.S. federal corporate tax rate from 35% to 21%. The Company remeasured deferred income taxes at the 21% federal tax rate as of December 31, 2017. The entities subject to regulatory construct have made their best estimate regarding the probability of settlements of net regulatory liabilities established pursuant to the TCJA. The amount of the settlements may change based on decisions and actions by the rate regulators, which could have a material impact on the Company’s future results of operations, cash flows or financial position. We revalued our deferred tax assets and liabilities as of December 31, 2017, which reflected our estimate of the impact of the TCJA. We will continue to evaluate subsequent regulations, clarifications and interpretations with the assumptions made, which could materially change our estimate.

Accrued Liabilities_

Accrued Liabilities:	6 Months Ended
	Jun. 30, 2018
Payables and Accruals [Abstract]
Accrued Liabilities	ACCRUED LIABILITIES The following amounts by major classification are included in Accrued liabilities in the accompanying Condensed Consolidated Balance Sheets (in thousands) as of: June 30, 2018 December 31, 2017 June 30, 2017 Accrued employee compensation, benefits and withholdings $ 49,225 $ 52,467 $ 44,658 Accrued property taxes 34,664 42,029 32,440 Customer deposits and prepayments 36,993 44,420 41,068 Accrued interest and contract adjustment payments 33,767 33,822 33,914 CIAC current portion 1,552 1,552 1,575 Other (none of which is individually significant) 34,138 45,172 38,151 Total accrued liabilities $ 190,339 $ 219,462 $ 191,806

Management's Statement (Policie

Management's Statement (Policies)	6 Months Ended
	Jun. 30, 2018
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Segment Reporting	Segment Reporting We conduct our operations through the following reportable segments: Electric Utilities, Gas Utilities, Power Generation and Mining. Our reportable segments are based on our method of internal reporting, which is generally segregated by differences in products, services and regulation. All of our operations and assets are located within the United States. On November 1, 2017, the BHC board of directors approved a complete divestiture of our Oil and Gas segment. The Oil and Gas segment assets and liabilities are classified as held for sale and the results of operations are shown in income (loss) from discontinued operations, excluding certain general and administrative costs and interest expense which do not meet the criteria for income (loss) from discontinued operations. As of June 30, 2018, we have sold nearly all oil and gas assets. Transaction closing for the last few assets and final accounting are expected within the third quarter. The closing of the oil and gas office will occur in August. See Note 18 for more information on discontinued operations.
Use of Estimates and Basis of Presentation	Use of Estimates and Basis of Presentation The information furnished in the accompanying Condensed Consolidated Financial Statements reflects certain estimates required and all adjustments, including accruals, which are, in the opinion of management, necessary for a fair presentation of the June 30, 2018 , December 31, 2017 , and June 30, 2017 financial information and are of a normal recurring nature. Certain industries in which we operate are highly seasonal, and revenue from, and certain expenses for, such operations may fluctuate significantly among quarterly periods. Demand for electricity and natural gas is sensitive to seasonal cooling, heating and industrial load requirements, as well as changes in market prices. In particular, the normal peak usage season for electric utilities is June through August while the normal peak usage season for gas utilities is November through March. Significant earnings variances can be expected between the Gas Utilities segment’s peak and off-peak seasons. Due to this seasonal nature, our results of operations for the three and six months ended June 30, 2018 and June 30, 2017 , and our financial condition as of June 30, 2018 , December 31, 2017 , and June 30, 2017 , are not necessarily indicative of the results of operations and financial condition to be expected as of or for any other period. All earnings per share amounts discussed refer to diluted earnings per share unless otherwise noted.
Cash and Cash Equivalents and Restricted Cash	Cash and Cash Equivalents and Restricted Cash For purposes of the cash flow statements, we consider all highly liquid investments with original maturities of three months or less at the time of purchase to be cash equivalents.
Investments	Investments We account for investments that we do not control under the cost method of accounting as we do not have the ability to exercise significant influence over the operating and financial policies of the investee. The cost method investments are recorded at cost and we record dividend income when applicable dividends are declared.
Recently Issued and Adopted Accounting Standards	Recently Issued Accounting Standards Leases, ASU 2016-02 In February 2016, the FASB issued ASU 2016-02, Leases (Topic 842) , which supersedes ASC 840, Leases. This ASU requires lessees to recognize a right-of-use asset and lease liability on the balance sheet for most leases, whereas today only financing-type lease liabilities (capital leases) are recognized on the balance sheet. In addition, the definition of a lease has been revised in regards to when an arrangement conveys the right to control the use of the identified asset under the arrangement which may result in changes to the classification of an arrangement as a lease. The ASU does not significantly change the lessees’ recognition, measurement and presentation of expenses and cash flows from the previous accounting standard. Lessors’ accounting under the ASU is largely unchanged from the previous accounting standard. The ASU expands the disclosure requirements of lease arrangements. Under the current guidance, lessees and lessors will use a modified retrospective transition approach, which requires application of the new guidance at the beginning of the earliest comparative period presented in the year of adoption. The guidance is effective for interim and annual reporting periods beginning after December 15, 2018, with early adoption permitted. In January 2018, the FASB issued amendments to the new lease standard, ASU No. 2018-01, allowing an entity to elect not to assess whether certain land easements are, or contain, leases when transitioning to the new lease standard. The FASB also issued additional amendments to the new lease standard in July 2018, ASU No. 2018-11, allowing companies to adopt the new standard with a cumulative effect adjustment as of the beginning of the year of adoption with prior year comparative financial information and disclosures remaining as previously reported. We expect to adopt this standard on January 1, 2019. For existing or expired land easements that were not previously accounted for as a lease, we anticipate electing the practical expedient which provides for no assessment of these easements. Further, we anticipate adopting the new standard with a cumulative effect adjustment with prior year comparative financial information remaining as previously reported when transitioning to the new standard. The standard also provides a transition practical expedient, commonly referred to as the “package of three”, that must be taken together and allows entities to (1) not reassess whether existing contracts contain leases, (2) carryforward the existing lease classification, and (3) not reassess initial direct costs associated with existing leases. We expect to elect the “package of three” practical expedient. We continue to evaluate the additional transition practical expedients available under the guidance and the impact of this new standard on our financial position, results of operations and cash flows. We are finalizing the process of identifying and categorizing our lease contracts and evaluating our current business processes relating to leases. We have selected and configured a new lease software solution that we are currently testing. We also continue to monitor utility industry lease implementation guidance that may change existing and future lease classification. Derivatives and Hedging: Targeted Improvements to Accounting for Hedging Activities, ASU 2017-12 In August 2017, the FASB issued ASU 2017-12, Derivatives and Hedging (Topic 815): Targeted Improvements to Accounting for Hedging Activities. This standard better aligns risk management activities and financial reporting for hedging relationships, simplifies hedge accounting requirements and improves disclosures of hedging arrangements. This ASU is effective for fiscal years beginning after December 15, 2018, with early adoption permitted. We do not anticipate the adoption of this guidance to have a material impact on our financial position, results of operations or cash flows. Simplifying the Test for Goodwill Impairment, ASU 2017-04 In January 2017, the FASB issued ASU 2017-04, Simplifying the Test for Goodwill Impairment (Topic 350) by eliminating step 2 from the goodwill impairment test. Under the new guidance, if the carrying amount of a reporting unit exceeds its fair value, an impairment loss will be recognized in an amount equal to that excess, limited to the amount of goodwill allocated to that reporting unit. The new standard is effective for interim and annual reporting periods beginning after December 15, 2019, applied on a prospective basis with early adoption permitted. We do not anticipate the adoption of this standard to have any impact on our financial position, results of operations or cash flows. Recently Adopted Accounting Standards Revenue from Contracts with Customers, ASU 2014-09 Effective January 1, 2018, we adopted ASU 2014-09, Revenue from Contracts with Customers (Topic 606) , and its related amendments (collectively known as ASC 606). Under this standard, revenue is recognized when a customer obtains control of promised goods or services in an amount that reflects the consideration the entity expects to receive in exchange for those goods or services. In addition, the standard requires disclosure of the nature, amount, timing and uncertainty of revenue and cash flows arising from contracts with customers. We applied the five-step method outlined in the ASU to all in-scope revenue streams and elected the modified retrospective implementation method. Implementation of the standard did not have a material impact on our financial position, results of operations or cash flows. Implementation of the standard did not have a significant impact on the measurement or recognition of revenue; therefore, no cumulative adoption adjustment to the opening balance of Retained earnings at the date of initial application was necessary. The additional disclosures required by the ASU are included in Note 2. Compensation - Retirement Benefits: Improving the Presentation of Net Periodic Pension Cost and Net Periodic Post-Retirement Benefit Cost, ASU 2017-07 Effective January 1, 2018, we adopted ASU 2017-07, Compensation – Retirement Benefits (Topic 715): Improving the Presentation of Net Periodic Pension Cost and Net Periodic Post-Retirement Benefit Cost . The standard requires employers to report the service cost component in the same line item(s) as other compensation costs, and require the other components of net periodic pension and post-retirement benefit costs to be separately presented in the income statement outside of income from operations. Additionally, only the service cost component may be eligible for capitalization, when applicable. However, all cost components remain eligible for capitalization under FERC regulations. The capitalization of only the service cost component of net periodic pension and post-retirement benefit costs in assets was applied on a prospective basis for the six months ended June 30, 2018. Retrospective impact was not material and therefore prior year presentation was not changed. For our rate-regulated entities, we capitalize the other components of net periodic benefit costs into regulatory assets or regulatory liabilities and maintain a FERC-to-GAAP reporting difference for these capitalized costs. The presentation changes required for net periodic pension and post-retirement costs resulted in offsetting changes to Operating income and Other income. Implementation of the standard did not have a material impact on our financial position, results of operations or cash flows. Statement of Cash Flows: Classification of Certain Cash Receipts and Cash Payments, ASU 2016-15 Effective January 1, 2018, we adopted ASU 2016-15, Statement of Cash Flows (Topic 230): Classification of Certain Cash Receipts and Cash Payments (a consensus of the Emerging Issues Task Force). This ASU requires changes in the presentation of certain items, including but not limited to, debt prepayment or debt extinguishment costs; contingent consideration payments made after a business combination; proceeds from the settlement of insurance claims; proceeds from the settlement of corporate-owned life insurance policies and distributions received from equity method investees. We implemented this standard effective January 1, 2018 using the retrospective transition method. This standard had no impact on our financial position, results of operations or cash flows. Statement of Cash Flows: Restricted Cash, ASU 2016-18 Effective January 1, 2018, we adopted ASU 2016-18, Statement of Cash Flows (Topic 230): Restricted Cash. This ASU provides guidance on the presentation of restricted cash or restricted cash equivalents and reduces the diversity in practice. This ASU requires amounts generally described as restricted cash and restricted cash equivalents to be included with cash and cash equivalents when reconciling beginning-of-period and end-of-period total amounts on the statement of cash flows. We elected, as permitted by the standard, to early adopt ASU 2016-18 retrospectively as of January 1, 2017 and have applied it to all periods presented herein. The adoption of ASU 2016-18 did not have a material impact to our condensed consolidated financial statements. The effect of the adoption of ASU 2016-18 on our Condensed Consolidated Statements of Cash Flows was to include restricted cash balances in the beginning and end of period balances of cash, cash equivalents, and restricted cash. The change in restricted cash was previously disclosed in investing activities in the Condensed Consolidated Statements of Cash Flows.
Revenue Recognition	Revenue Recognition Revenues are recognized in an amount that reflects the consideration we expect to receive in exchange for goods or services, when control of the promised goods or services is transferred to our customers. Our primary types of revenue contracts are: • Regulated natural gas and electric utility services tariffs - Our utilities have regulated operations, as defined by ASC 980, that provide services to regulated customers under rates, charges, terms and conditions of service, and prices determined by the jurisdictional regulators designated for our service territories. Collectively, these rates, charges, terms and conditions are included in a tariff, which governs all aspects of the provision of our regulated services. Our regulated services primarily encompass single performance obligations material to the context of the contract for delivery of either commodity natural gas, commodity electricity, natural gas transportation or electric transmission services. These service revenues are variable based on quantities delivered, influenced by seasonal business and weather patterns. Tariffs are only permitted to be changed through a rate-setting process involving the regulator-empowered statute to establish contractual rates between the utility and its customers. All of our utilities’ regulated sales are subject to regulatory-approved tariffs. • Power sales agreements - Our electric utilities and power generation segments have long-term wholesale power sales agreements with other load-serving entities, including affiliates, for the sale of excess power from owned generating units. These agreements include a combination of “take or pay” arrangements, where the customer is obligated to pay for the energy regardless of whether it actually takes delivery, as well as “requirements only” arrangements, where the customer is only obligated to pay for the energy the customer needs. In addition to these long-term contracts, Black Hills also sells excess energy to other load-serving entities on a short-term basis as a member of the Western States Power Pool. The pricing for all of these arrangements is included in the executed contracts or confirmations, reflecting the standalone selling price and is variable based on energy delivered. • Coal supply agreements - Our mining segment sells coal primarily under long-term contracts to utilities for use at their power generating plants, including affiliate electric utilities, and an affiliate non-regulated power generation entity. The contracts include a single promise to supply coal necessary to fuel the customers’ facilities during the contract term. The transaction price is established in the coal supply agreements, including cost-based agreements with the affiliated regulated utilities, and is variable based on tons of coal delivered. • Other non-regulated services - Our natural gas and electric utility segments also provide non-regulated services primarily comprised of appliance repair service and protection plans, electric and natural gas technical infrastructure construction and maintenance services, and in Nebraska and Wyoming, an unbundled natural gas commodity offering under the regulatory-approved Choice Gas Program. Revenue contracts for these services generally represent a single performance obligation with the price reflecting the standalone selling price stated in the agreement, and the revenue is variable based on the units delivered or services provided. The following tables depict the disaggregation of revenue, including intercompany revenue, from contracts with customers by customer type and timing of revenue recognition for each of the reporting segments, for the three and six months ended June 30, 2018 . Sales tax and other similar taxes are excluded from revenues. Three Months Ended June 30, 2018 Electric Utilities Gas Utilities Power Generation Mining Inter-company Revenues Total Customer types: (in thousands) Retail $ 145,377 $ 135,863 $ — $ 16,345 $ (7,979 ) $ 289,606 Transportation — 29,011 — — (301 ) 28,710 Wholesale 8,191 — 12,743 — (11,613 ) 9,321 Market - off-system sales 4,938 162 — — (1,660 ) 3,440 Transmission/Other 13,356 11,672 — — (3,644 ) 21,384 Revenue from contracts with customers 171,862 176,708 12,743 16,345 (25,197 ) 352,461 Other revenues 1,754 912 9,141 554 (9,118 ) 3,243 Total revenues $ 173,616 $ 177,620 $ 21,884 $ 16,899 $ (34,315 ) $ 355,704 Timing of revenue recognition: Services transferred at a point in time $ — $ — $ — $ 16,345 $ (7,978 ) $ 8,367 Services transferred over time 171,862 176,708 12,743 — (17,219 ) 344,094 Revenue from contracts with customers $ 171,862 $ 176,708 $ 12,743 $ 16,345 $ (25,197 ) $ 352,461 Six Months Ended June 30, 2018 Electric Utilities Gas Utilities Power Generation Mining Inter-company Revenues Total Customer types: (in thousands) Retail $ 292,434 $ 477,257 $ — $ 32,902 $ (15,821 ) $ 786,772 Transportation — 70,681 — — (710 ) 69,971 Wholesale 17,241 — 26,676 — (23,826 ) 20,091 Market - off-system sales 9,082 589 — — (4,182 ) 5,489 Transmission/Other 26,427 24,341 — — (7,275 ) 43,493 Revenue from contracts with customers 345,184 572,868 26,676 32,902 (51,814 ) 925,816 Other revenues 1,987 2,096 18,311 1,125 (18,242 ) 5,277 Total revenues $ 347,171 $ 574,964 $ 44,987 $ 34,027 $ (70,056 ) $ 931,093 Timing of revenue recognition: Services transferred at a point in time $ — $ — $ — $ 32,902 $ (15,820 ) $ 17,082 Services transferred over time 345,184 572,868 26,676 — (35,994 ) 908,734 Revenue from contracts with customers $ 345,184 $ 572,868 $ 26,676 $ 32,902 $ (51,814 ) $ 925,816 The majority of our revenue contracts are based on variable quantities delivered; any fixed consideration contracts with an expected duration of one year or more are immaterial to our consolidated revenues. Variable consideration constraints in the form of discounts, rebates, credits, price concessions, incentives, performance bonuses, penalties or other similar items are not material for our revenue contracts. We are the principal in our revenue contracts, as we have control over the services prior to those services being transferred to the customer. Revenue Not in Scope of ASC 606 Other revenues included in the tables above include our revenue accounted for under separate accounting guidance, including lease revenue under ASC 840 and alternative revenue programs revenue under ASC 980. The majority of our lease revenue is related to a 20-year power sale agreement between Colorado IPP and affiliate Colorado Electric. This agreement is accounted for as a direct financing lease whereby Colorado IPP receives revenue for energy delivered and related capacity payments. This lease revenue is eliminated in our consolidated revenues. Significant Judgments and Estimates TCJA Revenue Reserve The TCJA or “tax reform” signed into law on December 22, 2017, reduced the federal corporate income tax rate from 35% to 21% effective for tax years beginning after December 31, 2017. Black Hills has been collaborating with utility commissions in the states in which it provides utility service to deliver to customers the benefits of a lower corporate federal income tax rate beginning in 2018 with the passage of the TCJA. We estimated and recorded a reserve to revenue of approximately $8.0 million and $23 million during the three and six months ended June 30, 2018 , respectively. As of June 30, 2018 , $3.3 million has been returned to customers and approximately $19 million remains in reserve. Unbilled Revenue Revenues attributable to natural gas and electricity delivered to customers but not yet billed are estimated and accrued, and the related costs are charged to expense. Factors influencing the determination of unbilled revenues include estimates of delivered sales volumes based on weather information and customer consumption trends. Contract Balances The nature of our primary revenue contracts provides an unconditional right to consideration upon service delivery; therefore, no customer contract assets or liabilities exist. The unconditional right to consideration is represented by the balance in our Accounts Receivable further discussed in Note 4. We do not typically incur costs that would be capitalized to obtain or fulfill a contract. Practical Expedients Our revenue contracts generally provide for performance obligations that are fulfilled and transfer control to customers over time, represent a series of distinct services that are substantially the same, involve the same pattern of transfer to the customer, and provide a right to consideration from our customers in an amount that corresponds directly with the value to the customer for the performance completed to date. Therefore, we recognize revenue in the amount to which we have a right to invoice. We have revenue contract performance obligations with similar characteristics, and we reasonably expect that the financial statement impact of applying the new revenue recognition guidance to a portfolio of contracts would not differ materially from applying this guidance to the individual contracts or performance obligations within the portfolio. Therefore, we have elected the portfolio approach in applying the new revenue guidance.

Revenue (Tables)

Revenue (Tables)	6 Months Ended
	Jun. 30, 2018
Revenue from Contract with Customer [Abstract]
Disaggregation of Revenue	The following tables depict the disaggregation of revenue, including intercompany revenue, from contracts with customers by customer type and timing of revenue recognition for each of the reporting segments, for the three and six months ended June 30, 2018 . Sales tax and other similar taxes are excluded from revenues. Three Months Ended June 30, 2018 Electric Utilities Gas Utilities Power Generation Mining Inter-company Revenues Total Customer types: (in thousands) Retail $ 145,377 $ 135,863 $ — $ 16,345 $ (7,979 ) $ 289,606 Transportation — 29,011 — — (301 ) 28,710 Wholesale 8,191 — 12,743 — (11,613 ) 9,321 Market - off-system sales 4,938 162 — — (1,660 ) 3,440 Transmission/Other 13,356 11,672 — — (3,644 ) 21,384 Revenue from contracts with customers 171,862 176,708 12,743 16,345 (25,197 ) 352,461 Other revenues 1,754 912 9,141 554 (9,118 ) 3,243 Total revenues $ 173,616 $ 177,620 $ 21,884 $ 16,899 $ (34,315 ) $ 355,704 Timing of revenue recognition: Services transferred at a point in time $ — $ — $ — $ 16,345 $ (7,978 ) $ 8,367 Services transferred over time 171,862 176,708 12,743 — (17,219 ) 344,094 Revenue from contracts with customers $ 171,862 $ 176,708 $ 12,743 $ 16,345 $ (25,197 ) $ 352,461 Six Months Ended June 30, 2018 Electric Utilities Gas Utilities Power Generation Mining Inter-company Revenues Total Customer types: (in thousands) Retail $ 292,434 $ 477,257 $ — $ 32,902 $ (15,821 ) $ 786,772 Transportation — 70,681 — — (710 ) 69,971 Wholesale 17,241 — 26,676 — (23,826 ) 20,091 Market - off-system sales 9,082 589 — — (4,182 ) 5,489 Transmission/Other 26,427 24,341 — — (7,275 ) 43,493 Revenue from contracts with customers 345,184 572,868 26,676 32,902 (51,814 ) 925,816 Other revenues 1,987 2,096 18,311 1,125 (18,242 ) 5,277 Total revenues $ 347,171 $ 574,964 $ 44,987 $ 34,027 $ (70,056 ) $ 931,093 Timing of revenue recognition: Services transferred at a point in time $ — $ — $ — $ 32,902 $ (15,820 ) $ 17,082 Services transferred over time 345,184 572,868 26,676 — (35,994 ) 908,734 Revenue from contracts with customers $ 345,184 $ 572,868 $ 26,676 $ 32,902 $ (51,814 ) $ 925,816

Business Segment Information (T

Business Segment Information (Tables)	6 Months Ended
	Jun. 30, 2018
Segment Reporting Information, Additional Information [Abstract]
Segment Reporting	Segment information and Corporate and Other included in the accompanying Condensed Consolidated Statements of Income were as follows (in thousands): Three Months Ended June 30, 2018 External Operating Revenue Inter-company Operating Revenue Total Revenues Net income (loss) from continuing operations Contract Customers Other Revenues Contract Customers Other Revenues Segment: Electric $ 166,565 $ 1,754 $ 5,297 $ — $ 173,616 $ 21,890 Gas 176,399 912 309 — 177,620 (1,161 ) Power Generation (b) 1,130 348 11,613 8,793 21,884 4,772 Mining 8,367 229 7,978 325 16,899 3,005 Corporate and Other — — — — — (4,162 ) Inter-company eliminations — — (25,197 ) (9,118 ) (34,315 ) — Total $ 352,461 $ 3,243 $ — $ — $ 355,704 $ 24,344 Under our modified retrospective adoption of ASU 2014-09, revenues for the three and six months ended June 30, 2017 are not presented by contract type. Three Months Ended June 30, 2017 External Operating Revenue Inter-company Operating Revenue Net income (loss) from continuing operations Segment: Electric . $ 165,517 $ 2,936 $ 18,832 Gas 166,439 8 (272 ) Power Generation (b) 1,470 20,325 5,332 Mining 8,403 6,543 2,681 Corporate and Other — — (3,762 ) Inter-company eliminations — (29,812 ) — Total $ 341,829 $ — $ 22,811 Six Months Ended June 30, 2018 External Operating Revenue Inter-company Operating Revenue Total Revenues Net income (loss) from continuing operations Contract Customers Other Revenues Contract Customers Other Revenues Segment: Electric $ 333,743 $ 1,987 $ 11,441 $ — $ 347,171 $ 41,735 Gas (a) 572,141 2,096 727 — 574,964 106,459 Power Generation (b) 2,850 718 23,826 17,593 44,987 10,628 Mining 17,082 476 15,820 649 34,027 5,989 Corporate and Other — — — — — (5,120 ) Inter-company eliminations — — (51,814 ) (18,242 ) (70,056 ) — Total $ 925,816 $ 5,277 $ — $ — $ 931,093 $ 159,691 Six Months Ended June 30, 2017 External Operating Revenue Inter-company Operating Revenue Net income (loss) from continuing operations Segment: Electric $ 337,687 $ 6,790 $ 41,062 Gas 531,340 17 45,738 Power Generation (b) 3,572 41,790 11,862 Mining 16,758 14,734 5,571 Corporate and Other (c) — — (3,330 ) Inter-company eliminations — (63,331 ) — Total $ 889,357 $ — $ 100,903 ___________ (a) Net income from continuing operations available for common stock for the six months ended June 30, 2018 included a $49 million tax benefit resulting from legal entity restructuring. See Note 19 Income Taxes of the Notes to Condensed Consolidated Financial Statements for more information. (b) Net income from continuing operations available for common stock for the three and six months ended June 30, 2018 and June 30, 2017 reflects net income attributable to noncontrolling interests of $2.8 million and $6.5 million , and $3.1 million and $6.6 million , respectively. (c) Net income (loss) from continuing operations available for common stock for the six months ended June 30, 2017 included a $1.4 million tax benefit recognized from carryback claims for specified liability losses involving prior tax years.
Reconciliation of Assets from Segment to Consolidated	Segment information and Corporate balances included in the accompanying Condensed Consolidated Balance Sheets were as follows (in thousands): Total Assets (net of inter-company eliminations) as of: June 30, 2018 December 31, 2017 June 30, 2017 Segment: Electric (a) $ 2,902,925 $ 2,906,275 $ 2,901,570 Gas 3,367,247 3,426,466 3,242,461 Power Generation (a) 49,628 60,852 66,292 Mining 68,154 65,455 67,365 Corporate and Other 178,618 115,612 109,581 Discontinued operations 3,557 84,242 122,477 Total assets $ 6,570,129 $ 6,658,902 $ 6,509,746 __________ (a) The PPA under which Black Hills Colorado IPP provides generation to support Colorado Electric customers from the Pueblo Airport Generation Station is accounted for as a capital lease. As such, assets owned by our Power Generation segment are recorded at Colorado Electric under accounting for a capital lease.

Accounts Receivable (Tables)

Accounts Receivable (Tables)	6 Months Ended
	Jun. 30, 2018
Receivables [Abstract]
Accounts Receivable and Allowance for Doubtful Accounts	Following is a summary of Accounts receivable, net included in the accompanying Condensed Consolidated Balance Sheets (in thousands) as of: Accounts Unbilled Less Allowance for Accounts June 30, 2018 Receivable, Trade Revenue Doubtful Accounts Receivable, net Electric Utilities $ 44,577 $ 34,940 $ (503 ) $ 79,014 Gas Utilities 70,244 23,557 (3,517 ) 90,284 Power Generation 1,681 — — 1,681 Mining 3,158 — — 3,158 Corporate 1,475 — — 1,475 Total $ 121,135 $ 58,497 $ (4,020 ) $ 175,612 Accounts Unbilled Less Allowance for Accounts December 31, 2017 Receivable, Trade Revenue Doubtful Accounts Receivable, net Electric Utilities $ 39,347 $ 36,384 $ (586 ) $ 75,145 Gas Utilities 81,256 88,967 (2,495 ) 167,728 Power Generation 1,196 — — 1,196 Mining 2,804 — — 2,804 Corporate 1,457 — — 1,457 Total $ 126,060 $ 125,351 $ (3,081 ) $ 248,330 Accounts Unbilled Less Allowance for Accounts June 30, 2017 Receivable, Trade Revenue Doubtful Accounts Receivable, net Electric Utilities $ 41,635 $ 33,686 $ (466 ) $ 74,855 Gas Utilities 62,908 26,584 (2,535 ) 86,957 Power Generation 877 — — 877 Mining 2,904 — — 2,904 Corporate 1,167 — — 1,167 Total $ 109,491 $ 60,270 $ (3,001 ) $ 166,760

Regulatory Accounting (Tables)

Regulatory Accounting (Tables)	6 Months Ended
	Jun. 30, 2018
Regulatory Assets and Liabilities Disclosure [Abstract]
Schedule of Regulatory Assets and Liabilities	We had the following regulatory assets and liabilities (in thousands) as of: Maximum Amortization (in years) June 30, 2018 December 31, 2017 June 30, 2017 Regulatory assets Deferred energy and fuel cost adjustments (a) 1 $ 26,725 $ 20,187 $ 20,761 Deferred gas cost adjustments (a) 1 962 31,844 8,962 Gas price derivatives (a) 3 9,120 11,935 11,159 Deferred taxes on AFUDC (b) (f) 45 7,813 7,847 15,322 Employee benefit plans (c) 12 108,366 109,235 107,419 Environmental (a) subject to approval 1,000 1,031 1,070 Asset retirement obligations (a) 44 523 517 510 Loss on reacquired debt (a) 28 19,868 20,667 21,466 Renewable energy standard adjustment (a) subject to approval 1,179 1,088 768 Deferred taxes on flow through accounting (c) (f) 54 28,193 26,978 40,586 Decommissioning costs 10 11,806 13,287 14,681 Gas supply contract termination (a) 4 17,171 20,001 22,793 Other regulatory assets (a) 30 27,976 32,837 31,663 Total regulatory assets 260,702 297,454 297,160 Less current regulatory assets (50,565 ) (81,016 ) (53,061 ) Regulatory assets, non-current $ 210,137 $ 216,438 $ 244,099 Regulatory liabilities Deferred energy and gas costs (a) 1 $ 27,188 $ 3,427 $ 13,693 Employee benefit plan costs and related deferred taxes (c) (f) 12 39,820 40,629 67,297 Cost of removal (a) 44 141,954 130,932 125,598 Excess deferred income taxes (c) (d) 40 310,132 301,553 56 TCJA revenue reserve (e) subject to approval 19,312 — — Other regulatory liabilities (c) 25 11,625 8,585 9,666 Total regulatory liabilities 550,031 485,126 216,310 Less current regulatory liabilities (52,102 ) (6,832 ) (17,305 ) Regulatory liabilities, non-current $ 497,929 $ 478,294 $ 199,005 __________ (a) Recovery of costs, but we are not allowed a rate of return. (b) In addition to recovery of costs, we are allowed a rate of return. (c) In addition to recovery or repayment of costs, we are allowed a return on a portion of this amount or a reduction in rate base. (d) The increase in the regulatory tax liability is primarily related to the revaluation of deferred income tax balances at the lower income tax rate. As of June 30, 2018 and December 31, 2017, all of the liability was classified as non-current due to uncertainties around the timing and other regulatory decisions that will affect the amount of regulatory tax liability amortized and returned to customers through rate reductions of other revenue offsets in 2018. (e) As of June 30, 2018, the amortization periods are yet to be determined and subject to approval by our regulators. (f) The variance to the prior periods is primarily due to the TCJA.

Materials, Supplies and Fuel (T

Materials, Supplies and Fuel (Tables)	6 Months Ended
	Jun. 30, 2018
Inventory, Net [Abstract]
Materials, Supplies and Fuel	The following amounts by major classification are included in Materials, supplies and fuel in the accompanying Condensed Consolidated Balance Sheets (in thousands) as of: June 30, 2018 December 31, 2017 June 30, 2017 Materials and supplies $ 73,075 $ 69,732 $ 68,759 Fuel - Electric Utilities 2,821 2,962 3,106 Natural gas in storage held for distribution 19,558 40,589 23,623 Total materials, supplies and fuel $ 95,454 $ 113,283 $ 95,488

Investments (Tables)

Investments (Tables)	6 Months Ended
	Jun. 30, 2018
Long-term Investments [Abstract]
Investments	The following table presents the carrying value of our investments (in thousands) as of: June 30, 2018 December 31, 2017 June 30, 2017 Cost method investment $ 28,134 $ — $ — Cash surrender value of life insurance contracts 13,014 13,090 12,761 Total investments $ 41,148 $ 13,090 $ 12,761

Earnings Per Share (Tables)

Earnings Per Share (Tables)	6 Months Ended
	Jun. 30, 2018
Earnings Per Share [Abstract]
Schedule of Earnings Per Share Reconciliation	A reconciliation of share amounts used to compute Earnings (loss) per share in the accompanying Condensed Consolidated Statements of Income was as follows (in thousands): Three Months Ended June 30, Six Months Ended June 30, 2018 2017 2018 2017 Net income available for common stock $ 21,917 $ 22,195 $ 154,921 $ 98,718 Weighted average shares - basic 53,355 53,229 53,337 53,191 Dilutive effect of: Equity Units (a) 1,057 1,977 904 1,796 Equity compensation 108 178 120 192 Weighted average shares - diluted 54,520 55,384 54,361 55,179 __________ (a) Calculated using the treasury stock method.
Schedule of Antidilutive Securities Excluded from Computation of Earnings Per Share	The following outstanding securities were excluded in the computation of diluted net income (loss) per share as their inclusion would have been anti-dilutive (in thousands): Three Months Ended June 30, Six Months Ended June 30, 2018 2017 2018 2017 Equity compensation 15 — 17 — Anti-dilutive shares 15 — 17 —

Notes Payable, Current Maturi36

Notes Payable, Current Maturities and Debt (Tables)	6 Months Ended
	Jun. 30, 2018
Debt Disclosure [Abstract]
Schedule of Short-term Debt	We had the following notes payable outstanding in the accompanying Condensed Consolidated Balance Sheets (in thousands) as of: June 30, 2018 December 31, 2017 June 30, 2017 Balance Outstanding Letters of Credit Balance Outstanding Letters of Credit Balance Outstanding Letters of Credit Revolving Credit Facility $ — $ 11,448 $ — $ 26,848 $ — $ 24,540 CP Program 121,800 — 211,300 — 107,975 — Total $ 121,800 $ 11,448 $ 211,300 $ 26,848 $ 107,975 $ 24,540
Schedule of Credit Facility Covenants	Our Revolving Credit Facility and term loans require compliance with the following financial covenant at the end of each quarter: As of June 30, 2018 Covenant Requirement Consolidated Indebtedness to Capitalization Ratio 58% Less than 65%

Equity (Tables)

Equity (Tables)	6 Months Ended
	Jun. 30, 2018
Statement of Stockholders' Equity [Abstract]
Schedule of Stockholders Equity	A summary of the changes in equity is as follows: Six Months Ended June 30, 2018 Total Stockholders’ Equity Noncontrolling Interest Total Equity (in thousands) Balance at December 31, 2017 $ 1,708,974 $ 111,232 $ 1,820,206 Net income (loss) 154,921 6,453 161,374 Other comprehensive income (loss) 2,421 — 2,421 Dividends on common stock (50,879 ) — (50,879 ) Share-based compensation 3,194 — 3,194 Dividend reinvestment and stock purchase plan 219 — 219 Other stock transactions (4 ) — (4 ) Distribution to noncontrolling interest — (9,998 ) (9,998 ) Balance at June 30, 2018 $ 1,818,846 $ 107,687 $ 1,926,533 Six Months Ended June 30, 2017 Total Stockholders’ Equity Noncontrolling Interest Total Equity (in thousands) Balance at December 31, 2016 $ 1,614,639 $ 115,495 $ 1,730,134 Net income (loss) 98,718 6,632 105,350 Other comprehensive income (loss) 1,942 — 1,942 Dividends on common stock (47,544 ) — (47,544 ) Share-based compensation 4,133 — 4,133 Dividend reinvestment and stock purchase plan 1,530 — 1,530 Redeemable noncontrolling interest (886 ) — (886 ) Cumulative effect of ASU 2016-09 implementation 3,714 — 3,714 Other stock transactions (7 ) — (7 ) Distribution to noncontrolling interest — (8,335 ) (8,335 ) Balance at June 30, 2017 $ 1,676,239 $ 113,792 $ 1,790,031
Schedule of Variable Interest Entities	We have recorded the following assets and liabilities on our Condensed Consolidated Balance Sheets related to the VIE described above as of: June 30, 2018 December 31, 2017 June 30, 2017 (in thousands) Assets Current assets $ 11,462 $ 14,837 $ 12,042 Property, plant and equipment of variable interest entities, net $ 203,308 $ 208,595 $ 214,239 Liabilities Current liabilities $ 2,946 $ 4,565 $ 2,651

Risk Management Activities (Tab

Risk Management Activities (Tables)	6 Months Ended
	Jun. 30, 2018
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Contract or notional amounts and terms of marketing activities and derivative commodity instruments	The contract or notional amounts and terms of the natural gas derivative commodity instruments held at our utilities are composed of both long and short positions. We were in a net long position as of: June 30, 2018 December 31, 2017 June 30, 2017 Notional (MMBtus) Maximum Term (months) (a) Notional (MMBtus) Maximum Term (months) (a) Notional (MMBtus) Maximum Term (months) (a) Natural gas futures purchased 5,680,000 30 8,330,000 36 11,060,000 42 Natural gas options purchased, net 1,140,000 9 3,540,000 14 1,640,000 20 Natural gas basis swaps purchased 5,720,000 30 8,060,000 36 10,070,000 42 Natural gas over-the-counter swaps, net (b) 4,950,000 23 3,820,000 29 5,200,000 23 Natural gas physical contracts, net (c) 3,866,648 210 12,826,605 35 8,427,119 10 __________ (a) Term reflects the maximum forward period hedged. (b) As of June 30, 2018 , 2,452,000 MMBtus were designated as cash flow hedges for the natural gas over-the-counter swaps purchased. (c) Volumes exclude contracts that qualify for the normal purchase, normal sales exception.
Derivative Instruments, Gain (Loss)	The impacts of cash flow hedges on our Condensed Consolidated Statements of Income is presented below for the three and six months ended June 30, 2018 and 2017 (in thousands). Note that this presentation does not reflect gains or losses arising from the underlying physical transactions; therefore, it is not indicative of the economic profit or loss we realized when the underlying physical and financial transactions were settled. Three Months Ended June 30, 2018 Derivatives in Cash Flow Hedging Relationships Location of Reclassifications from AOCI into Income Amount of Gain/(Loss) Reclassified from AOCI into Income (Settlements) Location of Gain/(Loss) Recognized in Income on Derivative (Ineffective Portion) Amount of Gain/(Loss) Recognized in Income on Derivative (Ineffective Portion) Interest rate swaps Interest expense $ (713 ) Interest expense $ — Commodity derivatives Fuel, purchased power and cost of natural gas sold (163 ) Fuel, purchased power and cost of natural gas sold — Total $ (876 ) $ — Three Months Ended June 30, 2017 Derivatives in Cash Flow Hedging Relationships Location of Reclassifications from AOCI into Income Amount of Gain/(Loss) Reclassified from AOCI into Income (Settlements) Location of Gain/(Loss) Recognized in Income on Derivative (Ineffective Portion) Amount of Gain/(Loss) Recognized in Income on Derivative (Ineffective Portion) Interest rate swaps Interest expense $ (713 ) Interest expense $ — Commodity derivatives Net (loss) from discontinued operations 430 Net (loss) from discontinued operations — Commodity derivatives Fuel, purchased power and cost of natural gas sold (44 ) Fuel, purchased power and cost of natural gas sold — Total $ (327 ) $ — Six Months Ended June 30, 2018 Derivatives in Cash Flow Hedging Relationships Location of Reclassifications from AOCI into Income Amount of Gain/(Loss) Reclassified from AOCI into Income (Settlements) Location of Gain/(Loss) Recognized in Income on Derivative (Ineffective Portion) Amount of Gain/(Loss) Recognized in Income on Derivative (Ineffective Portion) Interest rate swaps Interest expense $ (1,426 ) Interest expense $ — Commodity derivatives Fuel, purchased power and cost of natural gas sold (784 ) Fuel, purchased power and cost of natural gas sold — Total $ (2,210 ) $ — Six Months Ended June 30, 2017 Derivatives in Cash Flow Hedging Relationships Location of Reclassifications from AOCI into Income Amount of Gain/(Loss) Reclassified from AOCI into Income (Settlements) Location of Gain/(Loss) Recognized in Income on Derivative (Ineffective Portion) Amount of Gain/(Loss) Recognized in Income on Derivative (Ineffective Portion) Interest rate swaps Interest expense $ (1,515 ) Interest expense $ — Commodity derivatives Net (loss) from discontinued operations 659 Net (loss) from discontinued operations — Commodity derivatives Fuel, purchased power and cost of natural gas sold 14 Fuel, purchased power and cost of natural gas sold — Total $ (842 ) $ — The following tables summarize the gains and losses arising from hedging transactions that were recognized as a component of other comprehensive income (loss) for the three and six months ended June 30, 2018 and 2017 . The amounts included in the tables below exclude gains and losses arising from ineffectiveness because these amounts, if any, are immediately recognized in the Condensed Consolidated Statements of Income as incurred. Three Months Ended June 30, 2018 2017 (in thousands) Increase (decrease) in fair value: Forward commodity contracts $ 48 $ 525 Recognition of (gains) losses in earnings due to settlements: Interest rate swaps 713 713 Forward commodity contracts 163 (386 ) Total other comprehensive income (loss) from hedging $ 924 $ 852 Six Months Ended June 30, 2018 2017 (in thousands) Increase (decrease) in fair value: Forward commodity contracts $ (249 ) $ 1,451 Recognition of (gains) losses in earnings due to settlements: Interest rate swaps 1,426 1,515 Forward commodity contracts 784 (673 ) Total other comprehensive income (loss) from hedging $ 1,961 $ 2,293 Derivatives Not Designated as Hedge Instruments The following table summarizes the impacts of derivative instruments not designated as hedge instruments on our Condensed Consolidated Statements of Income for the three and six months ended June 30, 2018 and 2017 (in thousands). Note that this presentation does not reflect gains or losses arising from the underlying physical transactions; therefore, it is not indicative of the economic profit or loss we realized when the underlying physical and financial transactions were settled. Three Months Ended June 30, 2018 2017 Derivatives Not Designated as Hedging Instruments Location of Gain/(Loss) on Derivatives Recognized in Income Amount of Gain/(Loss) on Derivatives Recognized in Income Amount of Gain/(Loss) on Derivatives Recognized in Income Commodity derivatives Net (loss) from discontinued operations $ — $ 26 Commodity derivatives Fuel, purchased power and cost of natural gas sold 771 (691 ) $ 771 $ (665 ) Six Months Ended June 30, 2018 2017 Derivatives Not Designated as Hedging Instruments Location of Gain/(Loss) on Derivatives Recognized in Income Amount of Gain/(Loss) on Derivatives Recognized in Income Amount of Gain/(Loss) on Derivatives Recognized in Income Commodity derivatives Net (loss) from discontinued operations $ — $ 143 Commodity derivatives Fuel, purchased power and cost of natural gas sold 1,025 (1,500 ) $ 1,025 $ (1,357 ) As discussed above, financial instruments used in our regulated utilities are not designated as cash flow hedges. However, there is no earnings impact because the unrealized gains and losses arising from the use of these financial instruments are recorded as Regulatory assets or Regulatory liabilities. The net unrealized losses included in our Regulatory assets or Regulatory liability accounts related to the hedges in our utilities were $9.1 million , $12 million and $11 million at June 30, 2018 , December 31, 2017 and June 30, 2017 , respectively.

Fair Value Measurements (Tables

Fair Value Measurements (Tables)	6 Months Ended
	Jun. 30, 2018
Fair Value Disclosures [Abstract]
Schedule of Fair Value Hierarchy, Measured on Recurring Basis	The following tables set forth by level within the fair value hierarchy present gross assets and gross liabilities and related offsetting cash collateral and counterparty netting as permitted by GAAP that were accounted for at fair value on a recurring basis for derivative instruments. As of June 30, 2018 Level 1 Level 2 Level 3 Cash Collateral and Counterparty Netting Total (in thousands) Assets: Commodity derivatives — Utilities $ — $ 1,035 $ — $ (363 ) $ 672 Total $ — $ 1,035 $ — $ (363 ) $ 672 Liabilities: Commodity derivatives — Utilities $ — $ 9,808 $ — $ (9,144 ) $ 664 Total $ — $ 9,808 $ — $ (9,144 ) $ 664 As of December 31, 2017 Level 1 Level 2 Level 3 Cash Collateral and Counterparty Netting Total (in thousands) Assets: Commodity derivatives — Utilities $ — $ 1,586 $ — $ (1,282 ) $ 304 Total $ — $ 1,586 $ — $ (1,282 ) $ 304 Liabilities: Commodity derivatives — Utilities $ — $ 13,756 $ — $ (11,497 ) $ 2,259 Total $ — $ 13,756 $ — $ (11,497 ) $ 2,259 As of June 30, 2017 Level 1 Level 2 Level 3 Cash Collateral and Counterparty Netting Total (in thousands) Assets: Commodity derivatives — Utilities $ — $ 1,622 $ — $ (977 ) $ 645 Total $ — $ 1,622 $ — $ (977 ) $ 645 Liabilities: Commodity derivatives — Utilities $ — $ 12,331 $ — $ (11,568 ) $ 763 Total $ — $ 12,331 $ — $ (11,568 ) $ 763
Schedule of Derivative Instruments Balance Sheet Location	The following tables present the fair value and balance sheet classification of our derivative instruments (in thousands): As of June 30, 2018 Balance Sheet Location Fair Value of Asset Derivatives Fair Value of Liability Derivatives Derivatives designated as hedges: Commodity derivatives Derivative assets — current $ 128 $ — Commodity derivatives Other assets, non-current 6 — Commodity derivatives Derivative liabilities — current — 305 Commodity derivatives Other deferred credits and other liabilities — 16 Total derivatives designated as hedges $ 134 $ 321 Derivatives not designated as hedges: Commodity derivatives Derivative assets — current $ 538 $ — Commodity derivatives Other assets, non-current — — Commodity derivatives Derivative liabilities — current — 180 Commodity derivatives Other deferred credits and other liabilities — 163 Total derivatives not designated as hedges $ 538 $ 343 As of December 31, 2017 Balance Sheet Location Fair Value of Asset Derivatives Fair Value of Liability Derivatives Derivatives designated as hedges: Commodity derivatives Derivative liabilities — current $ — $ 817 Commodity derivatives Other deferred credits and other liabilities — 67 Total derivatives designated as hedges $ — $ 884 Derivatives not designated as hedges: Commodity derivatives Derivative assets — current $ 304 $ — Commodity derivatives Derivative liabilities — current — 1,264 Commodity derivatives Other deferred credits and other liabilities — 111 Total derivatives not designated as hedges $ 304 $ 1,375 As of June 30, 2017 Balance Sheet Location Fair Value of Asset Derivatives Fair Value of Liability Derivatives Derivatives designated as hedges: Commodity derivatives Derivative assets — current $ 39 $ — Commodity derivatives Current assets held for sale 509 — Commodity derivatives Noncurrent assets held for sale 31 — Commodity derivatives Derivative liabilities — current — 140 Commodity derivatives Other deferred credits and other liabilities — 32 Commodity derivatives Current liabilities held for sale — 27 Total derivatives designated as hedges $ 579 $ 199 Derivatives not designated as hedges: Commodity derivatives Derivative assets — current $ 600 $ — Commodity derivatives Other assets, non-current 6 — Commodity derivatives Derivative liabilities — current — 536 Commodity derivatives Other deferred credits and other liabilities — 55 Commodity derivatives Current liabilities held for sale — 17 Total derivatives not designated as hedges $ 606 $ 608

Fair Value of Financial Instr40

Fair Value of Financial Instruments (Tables)	6 Months Ended
	Jun. 30, 2018
Fair Value Disclosures [Abstract]
Fair Value of Financial Instruments	The estimated fair values of our financial instruments, excluding derivatives which are presented in Note 12 , were as follows (in thousands) as of: June 30, 2018 December 31, 2017 June 30, 2017 Carrying Amount Fair Value Carrying Amount Fair Value Carrying Amount Fair Value Cash and cash equivalents (a) $ 8,630 $ 8,630 $ 15,420 $ 15,420 $ 11,528 $ 11,528 Restricted cash (a) $ 3,084 $ 3,084 $ 2,820 $ 2,820 $ 2,534 $ 2,534 Notes payable (b) $ 121,800 $ 121,800 $ 211,300 $ 211,300 $ 107,975 $ 107,975 Long-term debt, including current maturities (c) (d) $ 3,113,811 $ 3,234,780 $ 3,115,143 $ 3,350,544 $ 3,166,045 $ 3,377,891 __________ (a) Carrying value approximates fair value due to either the short-term length of maturity or variable interest rates that approximate prevailing market rates, and therefore is classified in Level 1 in the fair value hierarchy. (b) Notes payable consist of commercial paper borrowings and borrowings on our Revolving Credit Facility. Carrying value approximates fair value due to the short-term length of maturity; since these borrowings are not traded on an exchange, they are classified in Level 2 in the fair value hierarchy. (c) Long-term debt is valued based on observable inputs available either directly or indirectly for similar liabilities in active markets and therefore is classified in Level 2 in the fair value hierarchy. (d) Carrying amount of long-term debt is net of deferred financing costs.

Other Comprehensive Income (L41

Other Comprehensive Income (Loss) (Tables)	6 Months Ended
	Jun. 30, 2018
Statement of Comprehensive Income [Abstract]
Reclassification Out of Accumulated Other Comprehensive Income (Loss)	The following table details reclassifications out of AOCI and into net income. The amounts in parentheses below indicate decreases to net income in the Condensed Consolidated Statements of Income for the period, net of tax (in thousands): Location on the Condensed Consolidated Statements of Income Amount Reclassified from AOCI Three Months Ended Six Months Ended June 30, 2018 June 30, 2017 June 30, 2018 June 30, 2017 Gains and (losses) on cash flow hedges: Interest rate swaps Interest expense $ (713 ) $ (713 ) $ (1,426 ) $ (1,515 ) Commodity contracts Net (loss) from discontinued operations — 430 — 659 Commodity contracts Fuel, purchased power and cost of natural gas sold (163 ) (44 ) (784 ) 14 (876 ) (327 ) (2,210 ) (842 ) Income tax Income tax benefit (expense) 197 106 494 281 Total reclassification adjustments related to cash flow hedges, net of tax $ (679 ) $ (221 ) $ (1,716 ) $ (561 ) Amortization of components of defined benefit plans: Prior service cost Operations and maintenance $ 44 $ 49 $ 89 $ 97 Actuarial gain (loss) Operations and maintenance (622 ) (414 ) (1,244 ) (828 ) (578 ) (365 ) (1,155 ) (731 ) Income tax Income tax benefit (expense) 126 128 252 265 Total reclassification adjustments related to defined benefit plans, net of tax $ (452 ) $ (237 ) $ (903 ) $ (466 ) Total reclassifications $ (1,131 ) $ (458 ) $ (2,619 ) $ (1,027 )
Schedule of Accumulated Other Comprehensive Income (Loss)	Balances by classification included within AOCI, net of tax on the accompanying Condensed Consolidated Balance Sheets were as follows (in thousands): Interest Rate Swaps Commodity Derivatives Employee Benefit Plans Total As of December 31, 2017 $ (19,581 ) $ (518 ) $ (21,103 ) $ (41,202 ) Other comprehensive income (loss) before reclassifications — (198 ) — (198 ) Amounts reclassified from AOCI 1,122 594 903 2,619 Reclassifications of certain tax effects from AOCI 15 — 3 18 Ending Balance June 30, 2018 $ (18,444 ) $ (122 ) $ (20,197 ) $ (38,763 ) Interest Rate Swaps Commodity Derivatives Employee Benefit Plans Total Balance as of December 31, 2016 $ (18,109 ) $ (233 ) $ (16,541 ) $ (34,883 ) Other comprehensive income (loss) before reclassifications — 915 — 915 Amounts reclassified from AOCI 985 (424 ) 466 1,027 Ending Balance June 30, 2017 $ (17,124 ) $ 258 $ (16,075 ) $ (32,941 )

Supplemental Disclosure of Ca42

Supplemental Disclosure of Cash Flow Information (Tables)	6 Months Ended
	Jun. 30, 2018
Supplemental Cash Flow Information [Abstract]
Supplemental Disclosure of Cash Flow Information	Six Months Ended June 30, 2018 June 30, 2017 (in thousands) Non-cash investing and financing activities — Property, plant and equipment acquired with accrued liabilities $ 37,168 $ 31,579 Cash (paid) refunded during the period — Interest (net of amounts capitalized) $ (67,119 ) $ (65,820 ) Income taxes (paid) refunded $ (14,837 ) $ 1

Employee Benefit Plans (Tables)

Employee Benefit Plans (Tables)	6 Months Ended
	Jun. 30, 2018
Defined Benefit Plan [Abstract]
Schedule of Net Benefit Costs	The components of net periodic benefit cost for the Defined Benefit Pension Plan were as follows (in thousands): Three Months Ended June 30, Six Months Ended June 30, 2018 2017 2018 2017 Service cost $ 1,709 $ 1,759 $ 3,417 $ 3,517 Interest cost 3,868 3,880 7,735 7,760 Expected return on plan assets (6,185 ) (6,129 ) (12,370 ) (12,258 ) Prior service cost 14 15 29 29 Net loss (gain) 2,157 1,001 4,315 2,003 Net periodic benefit cost $ 1,563 $ 526 $ 3,126 $ 1,051 Defined Benefit Postretirement Healthcare Plans The components of net periodic benefit cost for the Defined Benefit Postretirement Healthcare Plans were as follows (in thousands): Three Months Ended June 30, Six Months Ended June 30, 2018 2017 2018 2017 Service cost $ 572 $ 575 $ 1,145 $ 1,150 Interest cost 521 534 1,042 1,067 Expected return on plan assets (56 ) (79 ) (113 ) (158 ) Prior service cost (benefit) (99 ) (109 ) (198 ) (218 ) Net loss (gain) 54 125 108 250 Net periodic benefit cost $ 992 $ 1,046 $ 1,984 $ 2,091 Supplemental Non-qualified Defined Benefit and Defined Contribution Plans The components of net periodic benefit cost for the Supplemental Non-qualified Defined Benefit and Defined Contribution Plans were as follows (in thousands): Three Months Ended June 30, Six Months Ended June 30, 2018 2017 2018 2017 Service cost $ 435 $ 609 $ 715 $ 1,436 Interest cost 292 319 585 638 Prior service cost 1 — 1 1 Net loss (gain) 250 250 500 500 Net periodic benefit cost $ 978 $ 1,178 $ 1,801 $ 2,575
Schedule of Defined Benefit Plans Contributions	Contributions made in 2018 and anticipated contributions for 2018 and 2019 are as follows (in thousands): Contributions Made Contributions Made Additional Contributions Contributions Three Months Ended June 30, 2018 Six Months Ended June 30, 2018 Anticipated for 2018 Anticipated for 2019 Defined Benefit Pension Plan $ — $ — $ 12,700 $ 12,700 Non-pension Defined Benefit Postretirement Healthcare Plans $ 1,234 $ 2,468 $ 2,468 $ 4,802 Supplemental Non-qualified Defined Benefit and Defined Contribution Plans $ 343 $ 686 $ 686 $ 1,921

Discontinued Operations (Tables

Discontinued Operations (Tables)	6 Months Ended
	Jun. 30, 2018
Discontinued Operations and Disposal Groups [Abstract]
Disposal Groups, Including Discontinued Operations, Balance Sheet Accounts	Held for sale assets and liabilities at June 30, 2017 are classified as current and non-current (in thousands) as of. June 30, 2018 December 31, 2017 June 30, 2017 Other current assets $ 378 $ 10,360 $ 8,193 Derivative assets, current and noncurrent — — 541 Deferred income tax assets, noncurrent, net — 16,966 20,654 Property, plant and equipment, net 3,179 56,916 93,089 Other current liabilities (4,295 ) (18,966 ) (10,860 ) Derivative liabilities, current and noncurrent — — (44 ) Deferred income tax liabilities, noncurrent, net (1,153 ) — — Other noncurrent liabilities — (22,808 ) (23,048 ) Net assets (liabilities) $ (1,891 ) $ 42,468 $ 88,525
Disposal Groups, Including Discontinued Operations, Income Statement	Operating results of the Oil and Gas segment included in Discontinued operations on the accompanying Condensed Consolidated Statements of Income were as follows (in thousands) for the period ended: Three Months Ended June 30, Six Months Ended June 30, 2018 2017 2018 2017 Revenue $ 1,284 $ 6,149 $ 5,199 $ 12,624 Operations and maintenance 2,718 5,491 8,407 12,696 Loss (gain) on sale of assets 1,991 (249 ) 2,203 (249 ) Depreciation, depletion and amortization — 1,838 1,300 3,783 Total operating expenses 4,709 7,080 11,910 16,230 Operating (loss) (3,425 ) (931 ) (6,711 ) (3,606 ) Other income (expense), net 90 65 119 138 Income tax benefit (expense) 908 250 1,822 1,283 (Loss) from discontinued operations $ (2,427 ) $ (616 ) $ (4,770 ) $ (2,185 )

Income Taxes (Tables)

Income Taxes (Tables)	6 Months Ended
	Jun. 30, 2018
Income Tax Disclosure [Abstract]
Schedule of Effective Income Tax Rate Reconciliation	The effective tax rate differs from the federal statutory rate as follows: Three Months Ended June 30, Tax (benefit) expense 2018 2017 Federal statutory rate 21.0 % 35.0 % State income tax (net of federal tax effect) 1.7 (0.1 ) Percentage depletion in excess of cost (0.4 ) (1.2 ) Noncontrolling interest (a) (1.0 ) (3.1 ) Tax credits (b) (2.1 ) (3.6 ) Effective tax rate adjustment (c) — 4.4 Flow-through adjustments (0.7 ) (2.6 ) TCJA change in estimate (d) 0.3 — AFUDC equity (0.1 ) (0.6 ) Other tax differences 0.7 0.9 19.4 % 29.1 % __________ (a) The adjustment reflects the non-controlling interest attributable to the sale of 49.9% of the membership interests of COIPP LLC in April 2016. (b) The tax credits are due to the production tax credits for the Peak View wind farm. (c) Adjustment to reflect our projected annual effective tax rate, pursuant to ASC 740-270. (d) The TCJA was signed into law on December 22, 2017. In accordance with ASC 740, net deferred tax assets and liabilities were revalued as of December 31, 2017 due to the reduction in the federal income tax rate from 35% to 21%. During the three months ended June 30, 2018, certain estimated items associated with the revaluation have been updated. Six Months Ended June 30, Tax (benefit) expense 2018 2017 Federal statutory rate 21.0 % 35.0 % State income tax (net of federal tax effect) 1.7 1.0 Percentage depletion in excess of cost (0.4 ) (0.6 ) Noncontrolling interest (1.0 ) (1.6 ) IRC 172(f) carryback claim (a) — (1.3 ) Tax credits (2.1 ) (1.8 ) Effective tax rate adjustment — (0.8 ) Flow-through adjustments (0.7 ) (1.0 ) TCJA change in estimate (b) 1.6 — AFUDC equity (0.1 ) — Jurisdictional simplification project (c) (33.7 ) — Other tax differences 0.6 0.4 (13.1 )% 29.3 % __________ (a) During the first quarter of 2017, the Company filed amended income tax returns for the years 2006 through 2008 to carryback specified liability losses in accordance with IRC172(f). As a result of filing the amended returns, the Company’s accrued tax liability interest decreased, certain valuation allowances increased and the previously recorded domestic production activities deduction decreased. (b) The TCJA was signed into law on December 22, 2017. In accordance with ASC 740, net deferred tax assets and liabilities were revalued as of December 31, 2017 due to the reduction in the federal income tax rate from 35% to 21%. During the six months ended June 30, 2018, certain estimated items associated with the revaluation have been updated. (c) Tax benefit from legal restructuring associated with amortizable goodwill as part of ongoing jurisdictional simplification.

Accrued Liabilities (Tables)

Accrued Liabilities (Tables)	6 Months Ended
	Jun. 30, 2018
Payables and Accruals [Abstract]
Schedule of Accrued Liabilities	The following amounts by major classification are included in Accrued liabilities in the accompanying Condensed Consolidated Balance Sheets (in thousands) as of: June 30, 2018 December 31, 2017 June 30, 2017 Accrued employee compensation, benefits and withholdings $ 49,225 $ 52,467 $ 44,658 Accrued property taxes 34,664 42,029 32,440 Customer deposits and prepayments 36,993 44,420 41,068 Accrued interest and contract adjustment payments 33,767 33,822 33,914 CIAC current portion 1,552 1,552 1,575 Other (none of which is individually significant) 34,138 45,172 38,151 Total accrued liabilities $ 190,339 $ 219,462 $ 191,806

Management's Statement (Details

Management's Statement (Details) - USD ($)	Jun. 30, 2018	Dec. 31, 2017	Jun. 30, 2017
Disaggregation of Revenue [Line Items]
Cumulative adoption adjustment to the opening balance	$ 652,642,000	$ 548,617,000	$ 512,498,000
Accounting Standards Update 2014-09
Disaggregation of Revenue [Line Items]
Cumulative adoption adjustment to the opening balance	$ 0

Revenue_ Disaggregation of Reve

Revenue: Disaggregation of Revenue (Details) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2018	Jun. 30, 2017	Jun. 30, 2018	Jun. 30, 2017
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	$ 352,461		$ 925,816
Other revenues	3,243		5,277
Total revenues	355,704	$ 341,829	931,093	$ 889,357
Retail
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	289,606		786,772
Transportation
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	28,710		69,971
Wholesale
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	9,321		20,091
Market - off-system sales
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	3,440		5,489
Transmission/Other
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	21,384		43,493
Services transferred at a point in time
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	8,367		17,082
Services transferred over time
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	344,094		908,734
Inter-company Revenues
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	(25,197)		(51,814)
Other revenues	(9,118)		(18,242)
Total revenues	(34,315)	(29,812)	(70,056)	(63,331)
Inter-company Revenues | Retail
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	(7,979)		(15,821)
Inter-company Revenues | Transportation
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	(301)		(710)
Inter-company Revenues | Wholesale
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	(11,613)		(23,826)
Inter-company Revenues | Market - off-system sales
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	(1,660)		(4,182)
Inter-company Revenues | Transmission/Other
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	(3,644)		(7,275)
Inter-company Revenues | Services transferred at a point in time
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	(7,978)		(15,820)
Inter-company Revenues | Services transferred over time
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	(17,219)		(35,994)
Electric Utilities
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	171,862		345,184
Other revenues	1,754		1,987
Total revenues	173,616	165,517	347,171	337,687
Electric Utilities | Retail
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	145,377		292,434
Electric Utilities | Transportation
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	0		0
Electric Utilities | Wholesale
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	8,191		17,241
Electric Utilities | Market - off-system sales
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	4,938		9,082
Electric Utilities | Transmission/Other
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	13,356		26,427
Electric Utilities | Services transferred at a point in time
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	0		0
Electric Utilities | Services transferred over time
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	171,862		345,184
Electric Utilities | Inter-company Revenues
Disaggregation of Revenue [Line Items]
Total revenues		2,936		6,790
Gas Utilities
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	176,708		572,868
Other revenues	912		2,096
Total revenues	177,620	166,439	574,964	531,340
Gas Utilities | Retail
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	135,863		477,257
Gas Utilities | Transportation
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	29,011		70,681
Gas Utilities | Wholesale
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	0		0
Gas Utilities | Market - off-system sales
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	162		589
Gas Utilities | Transmission/Other
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	11,672		24,341
Gas Utilities | Services transferred at a point in time
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	0		0
Gas Utilities | Services transferred over time
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	176,708		572,868
Gas Utilities | Inter-company Revenues
Disaggregation of Revenue [Line Items]
Total revenues		8		17
Power Generation
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	12,743		26,676
Other revenues	9,141		18,311
Total revenues	21,884	1,470	44,987	3,572
Power Generation | Retail
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	0		0
Power Generation | Transportation
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	0		0
Power Generation | Wholesale
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	12,743		26,676
Power Generation | Market - off-system sales
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	0		0
Power Generation | Transmission/Other
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	0		0
Power Generation | Services transferred at a point in time
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	0		0
Power Generation | Services transferred over time
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	12,743		26,676
Power Generation | Inter-company Revenues
Disaggregation of Revenue [Line Items]
Total revenues		20,325		41,790
Mining
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	16,345		32,902
Other revenues	554		1,125
Total revenues	16,899	8,403	34,027	16,758
Mining | Retail
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	16,345		32,902
Mining | Transportation
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	0		0
Mining | Wholesale
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	0		0
Mining | Market - off-system sales
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	0		0
Mining | Transmission/Other
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	0		0
Mining | Services transferred at a point in time
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	16,345		32,902
Mining | Services transferred over time
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	$ 0		$ 0
Mining | Inter-company Revenues
Disaggregation of Revenue [Line Items]
Total revenues		$ 6,543		$ 14,734

Revenue_ Significant Judgements

Revenue: Significant Judgements and Estimates (Details) - USD ($) $ in Thousands	3 Months Ended	6 Months Ended
	Jun. 30, 2018	Jun. 30, 2018	Dec. 31, 2017	Jun. 30, 2017
Regulatory Liabilities	$ 550,031	$ 550,031	$ 485,126	$ 216,310
Revenue refunded to customers as a result of the TCJA tax benefits		3,300
TCJA Revenue Reserve Subject to Refund
Estimated and recorded revenue reduction from TCJA tax benefits	8,000	23,000
Regulatory Liabilities	$ 19,312	$ 19,312	$ 0	$ 0

Business Segment Information_ I

Business Segment Information: Information Relating to Segment Statement of Income (Details) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2018	Jun. 30, 2017	Jun. 30, 2018	Jun. 30, 2017
Segment Reporting Information
Revenue from contracts with customers	$ 352,461		$ 925,816
Other revenues	3,243		5,277
Total revenues	355,704	$ 341,829	931,093	$ 889,357
Net income (loss) from continuing operations	24,344	22,811	159,691	100,903
Deferred income taxes			(21,419)	52,385
Net Income (Loss) Attributable to Redeemable Noncontrolling Interest	2,823	3,116	6,453	6,739
Net tax benefit				1,400
Other Restructuring
Segment Reporting Information
Deferred income taxes			49,000
Inter-company Revenues
Segment Reporting Information
Revenue from contracts with customers	(25,197)		(51,814)
Other revenues	(9,118)		(18,242)
Total revenues	(34,315)	(29,812)	(70,056)	(63,331)
Net income (loss) from continuing operations	0	0	0	0
Corporate
Segment Reporting Information
Net income (loss) from continuing operations	(4,162)	(3,762)	(5,120)	(3,330)
Consolidation, Eliminations
Segment Reporting Information
Revenue from contracts with customers	0		0
Other revenues	0		0
Total revenues		0		0
Electric Utilities
Segment Reporting Information
Revenue from contracts with customers	171,862		345,184
Other revenues	1,754		1,987
Total revenues	173,616	165,517	347,171	337,687
Net income (loss) from continuing operations	21,890	18,832	41,735	41,062
Electric Utilities | Inter-company Revenues
Segment Reporting Information
Total revenues		2,936		6,790
Gas Utilities
Segment Reporting Information
Revenue from contracts with customers	176,708		572,868
Other revenues	912		2,096
Total revenues	177,620	166,439	574,964	531,340
Net income (loss) from continuing operations	(1,161)	(272)	106,459	45,738
Gas Utilities | Inter-company Revenues
Segment Reporting Information
Total revenues		8		17
Power Generation
Segment Reporting Information
Revenue from contracts with customers	12,743		26,676
Other revenues	9,141		18,311
Total revenues	21,884	1,470	44,987	3,572
Net income (loss) from continuing operations	4,772	5,332	10,628	11,862
Net Income (Loss) Attributable to Redeemable Noncontrolling Interest	2,800	3,100	6,500	6,600
Power Generation | Inter-company Revenues
Segment Reporting Information
Total revenues		20,325		41,790
Mining
Segment Reporting Information
Revenue from contracts with customers	16,345		32,902
Other revenues	554		1,125
Total revenues	16,899	8,403	34,027	16,758
Net income (loss) from continuing operations	3,005	2,681	5,989	5,571
Mining | Inter-company Revenues
Segment Reporting Information
Total revenues		$ 6,543		$ 14,734
External Operating Revenue
Segment Reporting Information
Revenue from contracts with customers	0		0
Other revenues	0		0
External Operating Revenue | Electric Utilities
Segment Reporting Information
Revenue from contracts with customers	166,565		333,743
Other revenues	1,754		1,987
External Operating Revenue | Gas Utilities
Segment Reporting Information
Revenue from contracts with customers	176,399		572,141
Other revenues	912		2,096
External Operating Revenue | Power Generation
Segment Reporting Information
Revenue from contracts with customers	1,130		2,850
Other revenues	348		718
External Operating Revenue | Mining
Segment Reporting Information
Revenue from contracts with customers	8,367		17,082
Other revenues	229		476
Inter-company Operating Revenue | Electric Utilities | Inter-company Revenues
Segment Reporting Information
Revenue from contracts with customers	5,297		11,441
Other revenues	0		0
Inter-company Operating Revenue | Gas Utilities | Inter-company Revenues
Segment Reporting Information
Revenue from contracts with customers	309		727
Other revenues	0		0
Inter-company Operating Revenue | Power Generation | Inter-company Revenues
Segment Reporting Information
Revenue from contracts with customers	11,613		23,826
Other revenues	8,793		17,593
Inter-company Operating Revenue | Mining | Inter-company Revenues
Segment Reporting Information
Revenue from contracts with customers	7,978		15,820
Other revenues	$ 325		$ 649

Business Segment Information_ S

Business Segment Information: Segment and Corporate Assets (Details) - USD ($) $ in Thousands	Jun. 30, 2018	Dec. 31, 2017	Jun. 30, 2017
Segment Reporting, Asset Reconciling Item [Line Items]
Assets	$ 6,570,129	$ 6,658,902	$ 6,509,746
Corporate
Segment Reporting, Asset Reconciling Item [Line Items]
Assets	178,618	115,612	109,581
Electric Utilities
Segment Reporting, Asset Reconciling Item [Line Items]
Assets	2,902,925	2,906,275	2,901,570
Gas Utilities
Segment Reporting, Asset Reconciling Item [Line Items]
Assets	3,367,247	3,426,466	3,242,461
Power Generation
Segment Reporting, Asset Reconciling Item [Line Items]
Assets	49,628	60,852	66,292
Mining
Segment Reporting, Asset Reconciling Item [Line Items]
Assets	68,154	65,455	67,365
Discontinued Operations, Held-for-sale
Segment Reporting, Asset Reconciling Item [Line Items]
Assets	$ 3,557	$ 84,242	$ 122,477

Accounts Receivable (Details)

Accounts Receivable (Details) - USD ($) $ in Thousands	Jun. 30, 2018	Dec. 31, 2017	Jun. 30, 2017
Accounts Receivable [Line Items]
Accounts Receivable, Trade	$ 121,135	$ 126,060	$ 109,491
Unbilled Receivables, Current	58,497	125,351	60,270
Allowance for Doubtful Accounts	(4,020)	(3,081)	(3,001)
Accounts receivable, net	175,612	248,330	166,760
Corporate
Accounts Receivable [Line Items]
Accounts Receivable, Trade	1,475	1,457	1,167
Unbilled Receivables, Current	0	0	0
Allowance for Doubtful Accounts	0	0	0
Accounts receivable, net	1,475	1,457	1,167
Electric Utilities
Accounts Receivable [Line Items]
Accounts Receivable, Trade	44,577	39,347	41,635
Unbilled Receivables, Current	34,940	36,384	33,686
Allowance for Doubtful Accounts	(503)	(586)	(466)
Accounts receivable, net	79,014	75,145	74,855
Gas Utilities
Accounts Receivable [Line Items]
Accounts Receivable, Trade	70,244	81,256	62,908
Unbilled Receivables, Current	23,557	88,967	26,584
Allowance for Doubtful Accounts	(3,517)	(2,495)	(2,535)
Accounts receivable, net	90,284	167,728	86,957
Power Generation
Accounts Receivable [Line Items]
Accounts Receivable, Trade	1,681	1,196	877
Unbilled Receivables, Current	0	0	0
Allowance for Doubtful Accounts	0	0	0
Accounts receivable, net	1,681	1,196	877
Mining
Accounts Receivable [Line Items]
Accounts Receivable, Trade	3,158	2,804	2,904
Unbilled Receivables, Current	0	0	0
Allowance for Doubtful Accounts	0	0	0
Accounts receivable, net	$ 3,158	$ 2,804	$ 2,904

Regulatory Accounting (Details)

Regulatory Accounting (Details) - USD ($) $ in Thousands	6 Months Ended
	Jun. 30, 2018	Dec. 31, 2017	Jun. 30, 2017
Regulatory assets
Regulatory assets	$ 260,702	$ 297,454	$ 297,160
Less current regulatory assets	(50,565)	(81,016)	(53,061)
Regulatory assets, non-current	210,137	216,438	244,099
Regulatory liabilities
Regulatory liabilities	550,031	485,126	216,310
Less current regulatory liabilities	(52,102)	(6,832)	(17,305)
Regulatory liabilities, non-current	$ 497,929	478,294	199,005
Deferred energy and gas costs
Regulatory liabilities
Maximum Amortization (in years)	1 year
Regulatory liabilities	$ 27,188	3,427	13,693
Employee benefit plans
Regulatory liabilities
Maximum Amortization (in years)	12 years
Regulatory liabilities	$ 39,820	40,629	67,297
Cost of removal
Regulatory liabilities
Maximum Amortization (in years)	44 years
Regulatory liabilities	$ 141,954	130,932	125,598
Excess deferred income taxes
Regulatory liabilities
Maximum Amortization (in years)	40 years
Regulatory liabilities	$ 310,132	301,553	56
TCJA revenue reduction
Regulatory liabilities
Regulatory liabilities	$ 19,312	0	0
Other regulatory liabilities
Regulatory liabilities
Maximum Amortization (in years)	25 years
Regulatory liabilities	$ 11,625	8,585	9,666
Deferred energy and gas costs
Regulatory assets
Maximum Amortization (in years)	1 year
Regulatory assets	$ 26,725	20,187	20,761
Deferred gas cost adjustments
Regulatory assets
Maximum Amortization (in years)	1 year
Regulatory assets	$ 962	31,844	8,962
Gas price derivatives
Regulatory assets
Maximum Amortization (in years)	3 years
Regulatory assets	$ 9,120	11,935	11,159
Deferred taxes on AFUDC
Regulatory assets
Maximum Amortization (in years)	45 years
Regulatory assets	$ 7,813	7,847	15,322
Employee benefit plans
Regulatory assets
Maximum Amortization (in years)	12 years
Regulatory assets	$ 108,366	109,235	107,419
Environmental
Regulatory assets
Regulatory assets	$ 1,000	1,031	1,070
Asset retirement obligations
Regulatory assets
Maximum Amortization (in years)	44 years
Regulatory assets	$ 523	517	510
Loss on reacquired debt
Regulatory assets
Maximum Amortization (in years)	28 years
Regulatory assets	$ 19,868	20,667	21,466
Renewable energy standard adjustment
Regulatory assets
Regulatory assets	$ 1,179	1,088	768
Deferred taxes on flow through accounting
Regulatory assets
Maximum Amortization (in years)	54 years
Regulatory assets	$ 28,193	26,978	40,586
Decommissioning costs
Regulatory assets
Maximum Amortization (in years)	10 years
Regulatory assets	$ 11,806	13,287	14,681
Gas supply contract termination
Regulatory assets
Maximum Amortization (in years)	4 years
Regulatory assets	$ 17,171	20,001	22,793
Other regulatory assets
Regulatory assets
Maximum Amortization (in years)	30 years
Regulatory assets	$ 27,976	$ 32,837	$ 31,663

Regulatory Accounting_ TCJA Rev

Regulatory Accounting: TCJA Revenue Reserve (Details) - USD ($) $ in Millions	3 Months Ended	6 Months Ended
	Jun. 30, 2018	Jun. 30, 2018
Revenue refunded to customers as a result of the TCJA tax benefits		$ 3.3
Colorado Public Utilities Commission (CPUC)
Estimated and recorded revenue reduction from TCJA tax benefits		10.8
Iowa Utilities Board (IUB)
Estimated and recorded revenue reduction from TCJA tax benefits		2.2
Kansas Public Utilities Commission (KPUC)
Estimated and recorded revenue reduction from TCJA tax benefits		1.9
Nebraska Public Service Commission (NPSC)
Estimated and recorded revenue reduction from TCJA tax benefits		3.8
TCJA Revenue Reserve Subject to Refund
Estimated and recorded revenue reduction from TCJA tax benefits	$ 8	$ 23

Regulatory Accounting_ Rate Rev

Regulatory Accounting: Rate Review (Details) - USD ($) $ in Millions	Jul. 16, 2018	Jun. 01, 2018	Dec. 15, 2017	Jun. 30, 2018
Colorado Public Utilities Commission (CPUC)
Public Utilities, General Disclosures [Line Items]
Estimated and recorded revenue reduction from TCJA tax benefits				$ 10.8
Colorado Public Utilities Commission (CPUC) | Black Hills Energy, Rocky Mountain Natural Gas
Public Utilities, General Disclosures [Line Items]
Annual revenue increases and an extension of SSIR		$ 1.1
Return on equity		9.90%
Capital structure, equity		46.63%
Capital structure, debt		53.37%
Arkansas Public Service Commission (APSC) | Black Hills Energy, Arkansas
Public Utilities, General Disclosures [Line Items]
Public Utilities, Requested Rate Increase (Decrease), Amount			$ 30
Public Utilities, Property, Plant and Equipment, Cost Of Plant Investment			$ 160
Public Utilities, Requested Rate Increase (Decrease), Amended, Amount				$ 19
Subsequent Event | Wyoming Public Service Commission (WPSC) | Black Hills Energy, Wyoming Gas
Public Utilities, General Disclosures [Line Items]
Annual revenue increases and an extension of SSIR	$ 1
Return on equity	9.60%
Capital structure, equity	54.00%
Capital structure, debt	46.00%

Materials, Supplies and Fuel (D

Materials, Supplies and Fuel (Details) - USD ($) $ in Thousands	Jun. 30, 2018	Dec. 31, 2017	Jun. 30, 2017
Inventory, Net [Abstract]
Materials and supplies	$ 73,075	$ 69,732	$ 68,759
Fuel - Electric Utilities	2,821	2,962	3,106
Natural gas in storage held for distribution	19,558	40,589	23,623
Total materials, supplies and fuel	$ 95,454	$ 113,283	$ 95,488

Investments (Details)

Investments (Details) - USD ($) $ in Thousands	Feb. 28, 2018	Jun. 30, 2018	Dec. 31, 2017	Jun. 30, 2017
Investment [Line Items]
Total investments		$ 41,148	$ 13,090	$ 12,761
Cost method investment
Investment [Line Items]
Assets held for sale contributed in exchange for equity securities in a privately held company	$ 28,000
Total investments		28,134	0	0
Cash surrender value of life insurance contracts
Investment [Line Items]
Total investments		$ 13,014	$ 13,090	$ 12,761

Earnings Per Share_ Earnings Pe

Earnings Per Share: Earnings Per Share Reconciliation (Details) - USD ($) shares in Thousands, $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2018	Jun. 30, 2017	Jun. 30, 2018	Jun. 30, 2017
Earnings Per Share [Abstract]
Net income available for common stock	$ 21,917	$ 22,195	$ 154,921	$ 98,718
Weighted average shares - basic (in shares)	53,355	53,229	53,337	53,191
Dilutive effect of:
Equity Units (in shares)	1,057	1,977	904	1,796
Equity compensation (in shares)	108	178	120	192
Weighted average shares - diluted (in shares)	54,520	55,384	54,361	55,179

Earnings Per Share_ Anti-diluti

Earnings Per Share: Anti-dilutive shares (Details) - shares shares in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2018	Jun. 30, 2017	Jun. 30, 2018	Jun. 30, 2017
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Anti-dilutive shares	15	0	17	0
Equity compensation
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Anti-dilutive shares	15	0	17	0

Notes Payable, Current Maturi60

Notes Payable, Current Maturities and Debt: Schedule of Short-term Debt and Narrative (Details)	Jul. 30, 2018USD ($)credit_extension	Jun. 30, 2018USD ($)	Jun. 30, 2017USD ($)	Dec. 31, 2017USD ($)
Short-term Debt [Line Items]
Notes payable		$ 121,800,000	$ 107,975,000	$ 211,300,000
Letters of Credit		11,448,000	24,540,000	26,848,000
Commercial paper, maximum borrowing capacity		750,000,000
Net (payments) borrowings of short-term debt		(89,500,000)	11,375,000
Commercial Paper
Short-term Debt [Line Items]
Notes payable		$ 121,800,000	107,975,000	211,300,000
Debt term		397 days
Net (payments) borrowings of short-term debt		$ (90,000,000)
Short-term interest rate		2.29%
Revolving Credit Facility
Short-term Debt [Line Items]
Notes payable		$ 0	0	0
Letters of Credit		$ 11,448,000	$ 24,540,000	$ 26,848,000
Commitment fee		0.20%
Revolving Credit Facility | Base Rate
Short-term Debt [Line Items]
Interest rate		0.25%
Revolving Credit Facility | Eurodollar
Short-term Debt [Line Items]
Interest rate		1.25%
Revolving Credit Facility | Letter of Credit
Short-term Debt [Line Items]
Interest rate		1.25%
Subsequent Event | Revolving Credit Facility
Short-term Debt [Line Items]
Current borrowing capacity	$ 750,000,000
Number of extension options | credit_extension	2
Debt term	1 year
Maximum borrowing capacity	$ 1,000,000,000
Subsequent Event | Revolving Credit Facility | Base Rate
Short-term Debt [Line Items]
Interest rate	0.25%
Subsequent Event | Revolving Credit Facility | Eurodollar
Short-term Debt [Line Items]
Interest rate	1.25%
Subsequent Event | Revolving Credit Facility | Letter of Credit
Short-term Debt [Line Items]
Interest rate	1.25%

Notes Payable, Current Maturi61

Notes Payable, Current Maturities and Debt: Debt Covenants (Details)	Jun. 30, 2018
Revolving Credit Facility
Line of Credit Facility [Line Items]
Recourse Leverage Ratio	58.00%
Debt instrument, covenant, Leverage Recourse Ratio	0.65
Maximum
Line of Credit Facility [Line Items]
Consolidated Indebtedness to Capitalization Ratio	0.65

Notes Payable, Current Maturi62

Notes Payable, Current Maturities and Debt: Current Maturities (Details) - USD ($) $ in Thousands	Jun. 30, 2018	Dec. 31, 2017	Jun. 30, 2017
Debt Instrument [Line Items]
Current maturities of long-term debt	$ 255,743	$ 5,743	$ 5,743
Corporate | Black Hills Corporation | Senior Unsecured Notes Due 2019
Debt Instrument [Line Items]
Current maturities of long-term debt	250,000
Corporate | Black Hills Corporation | Corporate Term Loan Due June 2021
Debt Instrument [Line Items]
Current maturities of long-term debt	$ 5,700

Notes Payable, Current Maturi63

Notes Payable, Current Maturities and Debt: Long-Term Debt (Details) - USD ($) $ in Thousands	Jul. 30, 2018	Jun. 30, 2018
Corporate Term Loan Due July 2020 | Base Rate
Debt Instrument [Line Items]
Long-term Debt, Percentage Bearing Variable Interest, Percentage Rate		0.05%
Corporate Term Loan Due July 2020 | Eurodollar
Debt Instrument [Line Items]
Long-term Debt, Percentage Bearing Variable Interest, Percentage Rate		1.05%
Corporate Term Loan Due August 2019
Debt Instrument [Line Items]
Long-term Debt, Gross		$ 300,000
Subsequent Event | Corporate Term Loan Due July 2020
Debt Instrument [Line Items]
Long-term Debt, Gross	$ 300,000
Subsequent Event | Corporate Term Loan Due July 2020 | Base Rate
Debt Instrument [Line Items]
Long-term Debt, Percentage Bearing Variable Interest, Percentage Rate	0.00%
Subsequent Event | Corporate Term Loan Due July 2020 | Eurodollar
Debt Instrument [Line Items]
Long-term Debt, Percentage Bearing Variable Interest, Percentage Rate	0.75%

Equity_ Stockholders Equity Rec

Equity: Stockholders Equity Recap (Details) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2018	Jun. 30, 2017	Jun. 30, 2018	Jun. 30, 2017
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Total Equity, beginning balance			$ 1,820,206	$ 1,730,134
Net income (loss)			161,374	105,350
Other comprehensive income (loss)	$ 1,161	$ 789	2,421	1,942
Dividends on common stock			(50,879)	(47,544)
Share-based compensation			3,194	4,133
Dividend reinvestment and stock purchase plan			219	1,530
Redeemable noncontrolling interest				(886)
Cumulative effect of ASU 2016-09 implementation				3,714
Other stock transactions			(4)	(7)
Distribution to noncontrolling interest			(9,998)	(8,335)
Total Equity, ending balance	1,926,533	1,790,031	1,926,533	1,790,031
Total Stockholders’ Equity
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Total Equity, beginning balance			1,708,974	1,614,639
Net income (loss)			154,921	98,718
Other comprehensive income (loss)			2,421	1,942
Dividends on common stock			(50,879)	(47,544)
Share-based compensation			3,194	4,133
Dividend reinvestment and stock purchase plan			219	1,530
Redeemable noncontrolling interest				(886)
Cumulative effect of ASU 2016-09 implementation				3,714
Other stock transactions			(4)	(7)
Distribution to noncontrolling interest			0	0
Total Equity, ending balance	1,818,846	1,676,239	1,818,846	1,676,239
Noncontrolling Interest
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Total Equity, beginning balance			111,232	115,495
Net income (loss)			6,453	6,632
Other comprehensive income (loss)			0	0
Dividends on common stock			0	0
Share-based compensation			0	0
Dividend reinvestment and stock purchase plan			0	0
Redeemable noncontrolling interest				0
Cumulative effect of ASU 2016-09 implementation				0
Other stock transactions			0	0
Distribution to noncontrolling interest			(9,998)	(8,335)
Total Equity, ending balance	$ 107,687	$ 113,792	$ 107,687	$ 113,792

Equity_ At-the-Market Equity Of

Equity: At-the-Market Equity Offering Program (Details) - USD ($) $ in Millions	Aug. 04, 2017	Jun. 30, 2017
Statement of Stockholders' Equity [Abstract]
At The Market Equity Offering Program Authorized Aggregate Value	$ 300	$ 200

Equity_ Variable Interest Entit

Equity: Variable Interest Entities (Details) $ in Thousands	Apr. 14, 2016	Jun. 30, 2018USD ($)MW	Dec. 31, 2017USD ($)	Jun. 30, 2017USD ($)
Variable Interest Entity, Qualitative or Quantitative Information, Ownership Percentage	49.90%
Current assets		$ 380,652	$ 570,782	$ 359,256
Property, plant and equipment of variable interest entities, net		5,702,065	5,567,518	5,423,160
Current liabilities		$ 730,635	649,101	438,865
Variable Interest Entity, Primary Beneficiary
Electric Generation Capacity, Megawatts | MW		200
Variable Interest Entity, Qualitative or Quantitative Information, Ownership Percentage	49.90%
Current assets		$ 11,462	14,837	12,042
Property, plant and equipment of variable interest entities, net		203,308	208,595	214,239
Current liabilities		$ 2,946	$ 4,565	$ 2,651

Risk Management Activities_ Uti

Risk Management Activities: Utilities (Details) - Natural Gas, Distribution $ in Millions	6 Months Ended		12 Months Ended
	Jun. 30, 2018USD ($)MMBTU	Jun. 30, 2017MMBTU	Dec. 31, 2017MMBTU
Derivative [Line Items]
Cash Flow Hedge Gain (Loss) to be Reclassified within Twelve Months | $	$ 0.1
Future
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	5,680,000	11,060,000	8,330,000
Derivative, Remaining Maturity	30 months	42 months	36 months
Commodity Option
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	1,140,000	1,640,000	3,540,000
Derivative, Remaining Maturity	9 months	20 months	14 months
Basis Swap
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	5,720,000	10,070,000	8,060,000
Derivative, Remaining Maturity	30 months	42 months	36 months
Fixed for Float Swaps Purchased
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	4,950,000	5,200,000	3,820,000
Derivative, Remaining Maturity	23 months	23 months	29 months
Credit Risk Derivative Liabilities, at Fair Value | $	$ 0.7
Natural Gas Physical Purchases
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	3,866,648	8,427,119	12,826,605
Derivative, Remaining Maturity	210 months	10 months	35 months
Cash Flow Hedging
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount, Energy Measure	2,452,000

Risk Management Activities_ Fin

Risk Management Activities: Financing Activities (Details) $ in Millions	1 Months Ended
	Jan. 31, 2017USD ($)
Interest rate swaps
Derivative [Line Items]
Derivative Expired During the Period	$ 50

Risk Management Activities_ Dis

Risk Management Activities: Discontinued Operations (Details) - Discontinued Operations, Held-for-sale or Disposed of by Sale	Jun. 30, 2017MMBTUbbl
Crude Oil | Future
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	72,000
Crude Oil | Options Held
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	18,000
Natural Gas | Swap
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount | MMBTU	1,080,000

Risk Management Activities_ Cas

Risk Management Activities: Cash Flow Hedges (Details) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2018	Jun. 30, 2017	Jun. 30, 2018	Jun. 30, 2017
Derivative [Line Items]
Derivative Instruments, Gain (Loss) Recognized in Income, Ineffective Portion and Amount Excluded from Effectiveness Testing, Net	$ 0	$ 0	$ 0	$ 0
Cash Flow Hedging
Derivative [Line Items]
Derivative Instruments, Gain (Loss) Reclassified from Accumulated OCI into Income, Effective Portion, Net	(876)	(327)	(2,210)	(842)
Cash Flow Hedging | Designated as Hedging Instrument
Derivative [Line Items]
Derivative, Gain (Loss) on Derivative, Net	924	852	1,961	2,293
Cash Flow Hedging | Interest rate swaps | Designated as Hedging Instrument
Derivative [Line Items]
Derivative Instruments, Gain (Loss) Reclassified from Accumulated OCI into Income, Effective Portion, Net	713	713	1,426	1,515
Cash Flow Hedging | Commodity Contract | Designated as Hedging Instrument
Derivative [Line Items]
Derivative Instruments, Gain (Loss) Reclassified from Accumulated OCI into Income, Effective Portion, Net	163	(386)	784	(673)
Derivative Instruments, Gain (Loss) Recognized in Other Comprehensive Income (Loss), Effective Portion, Net	48	525	(249)	1,451
Interest Expense | Interest rate swaps
Derivative [Line Items]
Derivative Instruments, Gain (Loss) Recognized in Income, Ineffective Portion and Amount Excluded from Effectiveness Testing, Net	0	0	0	0
Interest Expense | Cash Flow Hedging | Interest rate swaps
Derivative [Line Items]
Derivative Instruments, Gain (Loss) Reclassified from Accumulated OCI into Income, Effective Portion, Net	(713)	(713)	(1,426)	(1,515)
Net (loss) from Discontinued Operations | Commodity Contract
Derivative [Line Items]
Derivative Instruments, Gain (Loss) Recognized in Income, Ineffective Portion and Amount Excluded from Effectiveness Testing, Net		0		0
Net (loss) from Discontinued Operations | Cash Flow Hedging | Commodity Contract
Derivative [Line Items]
Derivative Instruments, Gain (Loss) Reclassified from Accumulated OCI into Income, Effective Portion, Net		430		659
Cost of Sales | Commodity Contract
Derivative [Line Items]
Derivative Instruments, Gain (Loss) Recognized in Income, Ineffective Portion and Amount Excluded from Effectiveness Testing, Net	0	0	0	0
Cost of Sales | Cash Flow Hedging | Commodity Contract
Derivative [Line Items]
Derivative Instruments, Gain (Loss) Reclassified from Accumulated OCI into Income, Effective Portion, Net	$ (163)	$ (44)	$ (784)	$ 14

Risk Management Activities_ Der

Risk Management Activities: Derivatives Not Designated as Hedge Instruments (Details) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2018	Jun. 30, 2017	Jun. 30, 2018	Jun. 30, 2017	Dec. 31, 2017
Derivative [Line Items]
Regulatory assets	$ 260,702	$ 297,160	$ 260,702	$ 297,160	$ 297,454
Price Risk Derivative
Derivative [Line Items]
Regulatory assets	9,120	11,159	9,120	11,159	$ 11,935
Not Designated as Hedging Instrument
Derivative [Line Items]
Derivative, Gain (Loss) on Derivative, Net	771	(665)	1,025	(1,357)
Not Designated as Hedging Instrument | Sales Revenue, Net
Derivative [Line Items]
Derivative, Gain (Loss) on Derivative, Net	0	26	0	143
Not Designated as Hedging Instrument | Cost of Sales
Derivative [Line Items]
Derivative, Gain (Loss) on Derivative, Net	$ 771	$ (691)	$ 1,025	$ (1,500)

Fair Value Measurements_ Schedu

Fair Value Measurements: Schedule of Fair Values (Details) - Fair Value, Measurements, Recurring - USD ($) $ in Thousands	Jun. 30, 2018	Dec. 31, 2017	Jun. 30, 2017
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Asset, Fair Value, Gross Liability and Obligation to Return Cash, Offset	$ (363)	$ (1,282)	$ (977)
Derivative Liability, Fair Value, Gross Asset and Right to Reclaim Cash, Offset	(9,144)	(11,497)	(11,568)
Utilities Group
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Asset, Fair Value, Gross Liability and Obligation to Return Cash, Offset	(363)	(1,282)	(977)
Derivative Liability, Fair Value, Gross Asset and Right to Reclaim Cash, Offset	(9,144)	(11,497)	(11,568)
Estimate of Fair Value Measurement
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Assets, Total	672	304	645
Derivative Liabilities, Total	664	2,259	763
Estimate of Fair Value Measurement | Utilities Group
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Assets, Commodity Derivatives	672	304	645
Derivative Liabilities, Fair Value Disclosure	664	2,259	763
Fair Value, Inputs, Level 1
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Assets, Total	0	0	0
Derivative Liabilities, Total	0	0	0
Fair Value, Inputs, Level 1 | Utilities Group
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Assets, Commodity Derivatives	0	0	0
Derivative Liabilities, Fair Value Disclosure	0	0	0
Fair Value, Inputs, Level 2
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Assets, Total	1,035	1,586	1,622
Derivative Liabilities, Total	9,808	13,756	12,331
Fair Value, Inputs, Level 2 | Utilities Group
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Assets, Commodity Derivatives	1,035	1,586	1,622
Derivative Liabilities, Fair Value Disclosure	9,808	13,756	12,331
Fair Value, Inputs, Level 3
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Assets, Total	0	0	0
Derivative Liabilities, Total	0	0	0
Fair Value, Inputs, Level 3 | Utilities Group
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Assets, Commodity Derivatives	0	0	0
Derivative Liabilities, Fair Value Disclosure	$ 0	$ 0	$ 0

Fair Value Measurements_ Balanc

Fair Value Measurements: Balance Sheet Location (Details) - USD ($) $ in Thousands	Jun. 30, 2018	Dec. 31, 2017	Jun. 30, 2017
Designated as Hedging Instrument
Derivatives, Carrying Amount and Fair Value [Line Items]
Derivative Asset, Fair Value, Net	$ 134	$ 0	$ 579
Derivative Liability, Fair Value, Net	321	884	199
Not Designated as Hedging Instrument
Derivatives, Carrying Amount and Fair Value [Line Items]
Derivative Asset, Fair Value, Net	538	304	606
Derivative Liability, Fair Value, Net	343	1,375	608
Commodity Contract | Designated as Hedging Instrument | Derivative assets — current
Derivatives, Carrying Amount and Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	128		39
Derivative Asset, Fair Value, Gross Liability	0		0
Commodity Contract | Designated as Hedging Instrument | Other assets, non-current
Derivatives, Carrying Amount and Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	6
Derivative Asset, Fair Value, Gross Liability	0
Commodity Contract | Designated as Hedging Instrument | Current assets held for sale
Derivatives, Carrying Amount and Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset			509
Derivative Asset, Fair Value, Gross Liability			0
Commodity Contract | Designated as Hedging Instrument | Noncurrent assets held for sale
Derivatives, Carrying Amount and Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset			31
Derivative Asset, Fair Value, Gross Liability			0
Commodity Contract | Designated as Hedging Instrument | Derivative liabilities — current
Derivatives, Carrying Amount and Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Asset	0	0	0
Derivative Liability, Fair Value, Gross Liability	305	817	140
Commodity Contract | Designated as Hedging Instrument | Other deferred credits and other liabilities
Derivatives, Carrying Amount and Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Asset	0	0	0
Derivative Liability, Fair Value, Gross Liability	16	67	32
Commodity Contract | Designated as Hedging Instrument | Current liabilities held for sale
Derivatives, Carrying Amount and Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Asset			0
Derivative Liability, Fair Value, Gross Liability			27
Commodity Contract | Not Designated as Hedging Instrument | Derivative assets — current
Derivatives, Carrying Amount and Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	538	304	600
Derivative Asset, Fair Value, Gross Liability	0	0	0
Commodity Contract | Not Designated as Hedging Instrument | Other assets, non-current
Derivatives, Carrying Amount and Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	0		6
Derivative Asset, Fair Value, Gross Liability	0		0
Commodity Contract | Not Designated as Hedging Instrument | Derivative liabilities — current
Derivatives, Carrying Amount and Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Asset	0	0	0
Derivative Liability, Fair Value, Gross Liability	180	1,264	536
Commodity Contract | Not Designated as Hedging Instrument | Other deferred credits and other liabilities
Derivatives, Carrying Amount and Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Asset	0	0	0
Derivative Liability, Fair Value, Gross Liability	$ 163	$ 111	55
Commodity Contract | Not Designated as Hedging Instrument | Current liabilities held for sale
Derivatives, Carrying Amount and Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Asset			0
Derivative Liability, Fair Value, Gross Liability			$ 17

Fair Value of Financial Instr74

Fair Value of Financial Instruments (Details) - USD ($) $ in Thousands	Jun. 30, 2018	Dec. 31, 2017	Jun. 30, 2017
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Cash and cash equivalents	$ 8,630	$ 15,420	$ 11,528
Restricted cash	3,084	2,820	2,534
Notes payable	121,800	211,300	107,975
Carrying Amount
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Cash and cash equivalents	8,630	15,420	11,528
Restricted cash	3,084	2,820	2,534
Notes payable	121,800	211,300	107,975
Long-term debt, including current maturities	3,113,811	3,115,143	3,166,045
Fair Value
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Cash and cash equivalents, Fair Value	8,630	15,420	11,528
Restricted Cash Fair Value Disclosure	3,084	2,820	2,534
Notes payable, Fair Value	121,800	211,300	107,975
Long-term debt, including current maturities, Fair Value	$ 3,234,780	$ 3,350,544	$ 3,377,891

Other Comprehensive Income (L75

Other Comprehensive Income (Loss): Reclassification Out of Accumulated Other Comprehensive Income (Loss) (Details) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2018	Jun. 30, 2017	Jun. 30, 2018	Jun. 30, 2017
Reclassification Adjustment Out Of Accumulated Other Comprehensive Income [Line Items]
Interest expense	$ 35,425	$ 35,072	$ 70,880	$ 70,130
Fuel, purchased power and cost of natural gas sold	104,661	98,164	352,300	317,941
Operations and maintenance	118,282	111,897	234,378	226,449
Income (loss) before earnings (loss) of unconsolidated subsidiaries and income taxes	33,708	36,579	146,883	152,682
Income tax benefit (expense)	(6,541)	(10,652)	19,261	(45,040)
Net Income (Loss), Including Portion Attributable to Noncontrolling Interest	24,740	25,311	161,374	105,457
Reclassification Out Of Accumulated Other Comprehensive Income
Reclassification Adjustment Out Of Accumulated Other Comprehensive Income [Line Items]
Net Income (Loss), Including Portion Attributable to Noncontrolling Interest	(1,131)	(458)	(2,619)	(1,027)
Reclassification Out Of Accumulated Other Comprehensive Income | Accumulated Net Gain (Loss) from Designated or Qualifying Cash Flow Hedges
Reclassification Adjustment Out Of Accumulated Other Comprehensive Income [Line Items]
Income (loss) before earnings (loss) of unconsolidated subsidiaries and income taxes	(876)	(327)	(2,210)	(842)
Income tax benefit (expense)	197	106	494	281
Net Income (Loss), Including Portion Attributable to Noncontrolling Interest	(679)	(221)	(1,716)	(561)
Reclassification Out Of Accumulated Other Comprehensive Income | Accumulated Net Gain (Loss) from Designated or Qualifying Cash Flow Hedges | Interest Rate Contract
Reclassification Adjustment Out Of Accumulated Other Comprehensive Income [Line Items]
Interest expense	(713)	(713)	(1,426)	(1,515)
Reclassification Out Of Accumulated Other Comprehensive Income | Accumulated Net Gain (Loss) from Designated or Qualifying Cash Flow Hedges | Commodity Contract
Reclassification Adjustment Out Of Accumulated Other Comprehensive Income [Line Items]
Net (loss) from discontinued operations	0	430	0	659
Fuel, purchased power and cost of natural gas sold	(163)	(44)	(784)	14
Reclassification Out Of Accumulated Other Comprehensive Income | Accumulated Defined Benefit Plans Adjustment, Net Prior Service Cost (Credit)
Reclassification Adjustment Out Of Accumulated Other Comprehensive Income [Line Items]
Operations and maintenance	44	49	89	97
Reclassification Out Of Accumulated Other Comprehensive Income | Accumulated Defined Benefit Plans Adjustment, Net Unamortized Gain (Loss)
Reclassification Adjustment Out Of Accumulated Other Comprehensive Income [Line Items]
Operations and maintenance	(622)	(414)	(1,244)	(828)
Reclassification Out Of Accumulated Other Comprehensive Income | Accumulated Defined Benefit Plans Adjustment
Reclassification Adjustment Out Of Accumulated Other Comprehensive Income [Line Items]
Income (loss) before earnings (loss) of unconsolidated subsidiaries and income taxes	(578)	(365)	(1,155)	(731)
Income tax benefit (expense)	126	128	252	265
Net Income (Loss), Including Portion Attributable to Noncontrolling Interest	$ (452)	$ (237)	$ (903)	$ (466)

Other Comprehensive Income (L76

Other Comprehensive Income (Loss): Accumulated Other Comprehensive Income (Details) - USD ($) $ in Thousands	6 Months Ended
	Jun. 30, 2018	Jun. 30, 2017
AOCI Attributable to Parent, Net of Tax [Roll Forward]
Accumulated Other Comprehensive Income (Loss), Net of Tax, Period Start	$ (41,202)	$ (34,883)
Accumulated Other Comprehensive Income (Loss), Net of Tax, Period End	(38,763)	(32,941)
Accumulated Net Gain (Loss) from Cash Flow Hedges Attributable to Parent | Interest Rate Swaps
AOCI Attributable to Parent, Net of Tax [Roll Forward]
Accumulated Other Comprehensive Income (Loss), Net of Tax, Period Start	(19,581)	(18,109)
Other Comprehensive Income (Loss), before Reclassifications, Net of Tax	0	0
Reclassification from AOCI, Current Period, Tax	15
Accumulated Other Comprehensive Income (Loss), Net of Tax, Period End	(18,444)	(17,124)
Accumulated Net Gain (Loss) from Cash Flow Hedges Attributable to Parent | Interest Rate Swaps | Reclassification Out Of Accumulated Other Comprehensive Income
AOCI Attributable to Parent, Net of Tax [Roll Forward]
Reclassification from Accumulated Other Comprehensive Income, Current Period, Net of Tax	1,122	985
Accumulated Net Gain (Loss) from Cash Flow Hedges Attributable to Parent | Commodity Contract
AOCI Attributable to Parent, Net of Tax [Roll Forward]
Accumulated Other Comprehensive Income (Loss), Net of Tax, Period Start	(518)	(233)
Other Comprehensive Income (Loss), before Reclassifications, Net of Tax	(198)	915
Reclassification from AOCI, Current Period, Tax	0
Accumulated Other Comprehensive Income (Loss), Net of Tax, Period End	(122)	258
Accumulated Net Gain (Loss) from Cash Flow Hedges Attributable to Parent | Commodity Contract | Reclassification Out Of Accumulated Other Comprehensive Income
AOCI Attributable to Parent, Net of Tax [Roll Forward]
Reclassification from Accumulated Other Comprehensive Income, Current Period, Net of Tax	594	(424)
Accumulated Defined Benefit Plans Adjustment
AOCI Attributable to Parent, Net of Tax [Roll Forward]
Accumulated Other Comprehensive Income (Loss), Net of Tax, Period Start	(21,103)	(16,541)
Other Comprehensive Income (Loss), before Reclassifications, Net of Tax	0	0
Reclassification from AOCI, Current Period, Tax	3
Accumulated Other Comprehensive Income (Loss), Net of Tax, Period End	(20,197)	(16,075)
Accumulated Defined Benefit Plans Adjustment | Reclassification Out Of Accumulated Other Comprehensive Income
AOCI Attributable to Parent, Net of Tax [Roll Forward]
Reclassification from Accumulated Other Comprehensive Income, Current Period, Net of Tax	903	466
AOCI Attributable to Parent
AOCI Attributable to Parent, Net of Tax [Roll Forward]
Other Comprehensive Income (Loss), before Reclassifications, Net of Tax	(198)	915
Reclassification from AOCI, Current Period, Tax	18
AOCI Attributable to Parent | Reclassification Out Of Accumulated Other Comprehensive Income
AOCI Attributable to Parent, Net of Tax [Roll Forward]
Reclassification from Accumulated Other Comprehensive Income, Current Period, Net of Tax	$ 2,619	$ 1,027

Supplemental Disclosure of Ca77

Supplemental Disclosure of Cash Flow Information (Details) - USD ($) $ in Thousands	6 Months Ended
	Jun. 30, 2018	Jun. 30, 2017
Non-cash Investing and Financing Activities from Continuing Operations [Abstract]
Property, plant and equipment acquired with accrued liabilities	$ 37,168	$ 31,579
Supplemental Cash Flow Elements [Abstract]
Interest (net of amounts capitalized)	(67,119)	(65,820)
Income taxes (paid) refunded	$ (14,837)	$ 1

Employee Benefit Plans (Details

Employee Benefit Plans (Details) - USD ($) $ in Thousands	Jul. 25, 2018	Jun. 30, 2018	Jun. 30, 2017	Jun. 30, 2018	Jun. 30, 2017
Defined Benefit Pension Plans
Defined Benefit Plan, Net Periodic Benefit Cost (Credit) [Abstract]
Service cost		$ 1,709	$ 1,759	$ 3,417	$ 3,517
Interest cost		3,868	3,880	7,735	7,760
Expected return on plan assets		(6,185)	(6,129)	(12,370)	(12,258)
Prior service cost (benefit)		14	15	29	29
Net loss (gain)		2,157	1,001	4,315	2,003
Net periodic benefit cost		1,563	526	3,126	1,051
Payment for Pension and Other Postretirement Benefits [Abstract]
Contributions by Employer		0		0
Estimated Future Employer Contributions in Current Fiscal Year		12,700		12,700
Estimated Future Employer Contributions in Next Fiscal Year		12,700		12,700
Defined Benefit Pension Plans | Subsequent Event
Payment for Pension and Other Postretirement Benefits [Abstract]
Contributions made to the Defined Benefit Pension Plan	$ 13,000
Defined Benefit Postretirement Healthcare Plans
Defined Benefit Plan, Net Periodic Benefit Cost (Credit) [Abstract]
Service cost		572	575	1,145	1,150
Interest cost		521	534	1,042	1,067
Expected return on plan assets		(56)	(79)	(113)	(158)
Prior service cost (benefit)		(99)	(109)	(198)	(218)
Net loss (gain)		54	125	108	250
Net periodic benefit cost		992	1,046	1,984	2,091
Payment for Pension and Other Postretirement Benefits [Abstract]
Contributions by Employer		1,234		2,468
Estimated Future Employer Contributions in Current Fiscal Year		2,468		2,468
Estimated Future Employer Contributions in Next Fiscal Year		4,802		4,802
Supplemental Non-qualified Defined Benefit and Defined Contribution Plans
Defined Benefit Plan, Net Periodic Benefit Cost (Credit) [Abstract]
Service cost		435	609	715	1,436
Interest cost		292	319	585	638
Prior service cost (benefit)		1	0	1	1
Net loss (gain)		250	250	500	500
Net periodic benefit cost		978	$ 1,178	1,801	$ 2,575
Payment for Pension and Other Postretirement Benefits [Abstract]
Contributions by Employer		343		686
Estimated Future Employer Contributions in Current Fiscal Year		686		686
Estimated Future Employer Contributions in Next Fiscal Year		$ 1,921		$ 1,921

Commitments and Contingencies_

Commitments and Contingencies: Dividend Restrictions (Details) $ in Millions	Jun. 30, 2018USD ($)
Utilities Group
Related Party Transaction [Line Items]
Restricted Net Assets for Subsidiaries	$ 257

Discontinued Operations_ Impair

Discontinued Operations: Impairment of Long-Lived Assets (Details) - USD ($)	3 Months Ended	12 Months Ended
	Jun. 30, 2018	Dec. 31, 2017
Discontinued Operations, Held-for-sale or Disposed of by Sale
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Disposal Group, Including Discontinued Operations, Impairment Of Long-lived Assets (Net of Tax)	$ 0	$ 13,000,000

Discontinued Operations (Detail

Discontinued Operations (Details) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2018	Jun. 30, 2017	Jun. 30, 2018	Jun. 30, 2017	Dec. 31, 2017
Disposal Group, Including Discontinued Operation, Balance Sheet Disclosures [Abstract]
Other current assets	$ 378	$ 8,193	$ 378	$ 8,193	$ 10,360
Derivative assets, current and noncurrent	0	541	0	541	0
Deferred income tax assets, noncurrent, net	0	20,654	0	20,654	16,966
Property, plant and equipment, net	3,179	93,089	3,179	93,089	56,916
Other current liabilities	(4,295)	(10,860)	(4,295)	(10,860)	(18,966)
Derivative liabilities, current and noncurrent	0	(44)	0	(44)	0
Deferred income tax liabilities, noncurrent, net	(1,153)	0	(1,153)	0	0
Other noncurrent liabilities	0	(23,048)	0	(23,048)	(22,808)
Net liabilities	(1,891)		(1,891)
Net assets		88,525		88,525	$ 42,468
Disposal Group, Including Discontinued Operation, Income Statement Disclosures [Abstract]
Revenue	1,284	6,149	5,199	12,624
Operations and maintenance	2,718	5,491	8,407	12,696
Loss (gain) on sale of assets	1,991	(249)	2,203	(249)
Depreciation, depletion and amortization	0	1,838	1,300	3,783
Total operating expenses	4,709	7,080	11,910	16,230
Operating (loss)	(3,425)	(931)	(6,711)	(3,606)
Other income (expense), net	90	65	119	138
Income tax benefit (expense)	908	250	1,822	1,283
(Loss) from discontinued operations	$ (2,427)	$ (616)	$ (4,770)	$ (2,185)

Income Taxes (Details)

Income Taxes (Details)	Apr. 14, 2016	Jun. 30, 2018	Jun. 30, 2017	Jun. 30, 2018	Jun. 30, 2017
Effective Income Tax Rate Reconciliation, Percent [Abstract]
Federal statutory rate		21.00%	35.00%	21.00%	35.00%
State income tax (net of federal tax effect)		1.70%	(0.10%)	1.70%	1.00%
Percentage depletion in excess of cost		(0.40%)	(1.20%)	(0.40%)	(0.60%)
Noncontrolling interest		(1.00%)	(3.10%)	(1.00%)	(1.60%)
IRC 172(f) carryback claim				0.00%	(1.30%)
Tax credits		(2.10%)	(3.60%)	(2.10%)	(1.80%)
Effective tax rate adjustment		0.00%	4.40%	0.00%	(0.80%)
Flow-through adjustments		(0.70%)	(2.60%)	(0.70%)	(1.00%)
TCJA change in estimate		0.30%	0.00%	1.60%	0.00%
AFUDC equity		(0.10%)	(0.60%)	(0.10%)	0.00%
Jurisdictional simplification project (c)				(33.70%)	0.00%
Other tax differences		0.70%	0.90%	0.60%	0.40%
Effective Tax Rate		19.40%	29.10%	(13.10%)	29.30%
Variable Interest Entity, Qualitative or Quantitative Information, Ownership Percentage	49.90%

Income Taxes_ Tax Benefit Relat

Income Taxes: Tax Benefit Related to Legal Restructuring (Details) - USD ($) $ in Thousands	6 Months Ended
	Jun. 30, 2018	Jun. 30, 2017
Deferred Tax Assets, Goodwill and Intangible Assets	$ 49,000
Deferred income taxes	(21,419)	$ 52,385
Other Restructuring
Deferred income taxes	$ 49,000

Accrued Liabilities (Details)

Accrued Liabilities (Details) - USD ($) $ in Thousands	Jun. 30, 2018	Dec. 31, 2017	Jun. 30, 2017
Payables and Accruals [Abstract]
Accrued employee compensation, benefits and withholdings	$ 49,225	$ 52,467	$ 44,658
Accrued property taxes	34,664	42,029	32,440
Customer deposits and prepayments	36,993	44,420	41,068
Accrued interest and contract adjustment payments	33,767	33,822	33,914
CIAC current portion	1,552	1,552	1,575
Other (none of which is individually significant)	34,138	45,172	38,151
Total accrued liabilities	$ 190,339	$ 219,462	$ 191,806